WWP69MRN.txt

1 SANDPOINT, IDAHO, WEDNESDAY, JUNE 9, 1999, 8:30 A. M.

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4 COMMISSIONER SMITH: Good morning, ladies

5 and gentlemen. We'll resume with our hearing. I

6 believe, Mr. Meyer, we're ready for another of your

7 witnesses.

8 MR. MEYER: Great. I call to the stand

9 Mr. Falkner.

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11 DON M. FALKNER,

12 produced as a witness at the instance of Avista

13 Corporation, having been first duly sworn, was examined

14 and testified as follows:

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16 DIRECT EXAMINATION

17

18 BY MR. MEYER:

19 Q For the record, would you please state your

20 name and your employer?

21 A Don M. Falkner with Avista Corp.

22 Q And have you prepared both direct and

23 rebuttal testimony?

24 A Yes, I have.

25 Q Any changes to that testimony?

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CSB REPORTING FALKNER (Di)
Wilder, Idaho 83676 Avista

1 A No.

2 Q So if I were to ask you the questions that

3 appear in your direct and your rebuttal testimony, would

4 your answers be the same?

5 A Yes, they would.

6 Q And are you sponsoring what have been

7 marked for identification as Exhibits 11, 12, 13, as well

8 as Exhibit 24?

9 A I'm sponsoring actually Exhibits 10, 11,

10 12, 13, and Exhibit 24.

11 Q Oh, thank you, I missed one. Would you

12 have any corrections to those exhibits?

13 A No.

14 Q If I were to ask you the questions that

15 appear, then, in your prefiled direct and rebuttal, would

16 your answers be the same?

17 A Yes, they would.

18 MR. MEYER: I'd ask that the testimony be

19 entered into the record and that the Exhibits 10 through

20 13 and 24 be introduced.

21 COMMISSIONER SMITH: Without objection, the

22 prefiled testimony of Mr. Falkner will be spread upon the

23 record as if read and Exhibit Nos. 10 through 13 and 24

24 will be introduced.

25 MR. MEYER: Thank you.

567

CSB REPORTING FALKNER (Di)
Wilder, Idaho 83676 Avista

1 (Avista Corporation Exhibit Nos. 10-13

2 & 24 were admitted into evidence.)

3 (The following prefiled direct and

4 rebuttal testimony of Mr. Don Falkner is spread upon the

5 record.)

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CSB REPORTING FALKNER (Di)
Wilder, Idaho 83676 Avista

1 Q. Please state your name, business address,

2 and present position with The Washington Water Power

3 Company?

4 A. My name is Don M. Falkner. My business

5 address is East 1411 Mission Avenue, Spokane, Washington.

6 I am employed by The Washington Water Power Company

7 (Company) as a Senior Rate Accountant.

8 Q. Would you please describe your education

9 and business experience?

10 A. I graduated from Washington State

11 University in February of 1981 with a Bachelor of Arts

12 Degree in Business Administration majoring in Accounting.

13 That same year, I passed the May Certified Public

14 Accountant exam and joined The Company in June. I have

15 served in various positions within the sections of the

16 Finance Department, including Power Supply Accounting,

17 Subsidiary Accounting, Budget and Forecasting, Plant

18 Accounting and Corporate Accounting. For the past 8

19 years, I have served in the Rates and Tariff

20 Administration Section, which is part of The Company's

21 External Relations Department.

22 Q. As a Senior Rate Accountant, what are your

23 responsibilities?

24 A. As a Senior Rate Accountant, aside from

25 special projects, I am responsible for preparation of

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WWP

1 normalized semi-annual Commission Basis reporting in the

2 various jurisdictions in which The Company provides

3 utility services.

4 Q. Have you previously testified before this

5 Commission?

6 A. Yes. I testified before this Commission in

7 1993 in Case No(s). WWP-E-92-5 and WWP-G-92-2.

8 Q. What is the scope of your testimony in this

9 proceeding?

10 A. My testimony and exhibits in this

11 proceeding will generally cover

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1 accounting and financial data in support of the Company's

2 need for the proposed increase in rates. I will explain

3 pro formed operating results including expense and rate

4 base adjustments made to actual operating results and

5 rate base. Witnesses Hirschkorn and Norwood were

6 responsible for the preparation of the pro forma revenue

7 adjustment and the pro forma power supply adjustment,

8 respectively. I will cover each of those adjustments

9 briefly while their testimonies will provide more

10 in-depth discussions. My testimony will also cover the

11 system and jurisdictional allocations used in preparation

12 of the Company's pro forma results of operations study

13 presented in this proceeding as well as some discussion

14 of the Company's energy efficiency programs in Idaho.

15 Q. Are you sponsoring any exhibits to be

16 introduced in this proceeding?

17 A. Yes. I am sponsoring Exhibit No(s). 10,

18 11, 12 and 13, as previously marked for identification,

19 which were prepared under my supervision and direction.

20 Q. On what test period is the Company basing

21 its needs for additional revenue?

22 A. The test period being used by the Company

23 is the twelve month period ending December 31, 1997

24 presented on a pro forma basis.

25 Q. What is the Company's Rate of Return that

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1 was last authorized by this Commission for its electric

2 operations in Idaho?

3 A. The Company's currently authorized Rate of

4 Return for its Idaho electric operations is 10.95%. That

5 rate dates back to Case No. U-1008-256, which became

6 effective in September of 1986.

7 Q. Have there been any changes to base

8 electric rates in the Idaho jurisdiction since 1986?

9 A. No. The Company has not changed its base,

10 or general Idaho electric rates

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1 for over 12 years. However, a Demand Side Management

2 Tariff Rider (Tariff Rider) was implemented in March 1995

3 in which a surcharge of 1.5% is being used to fund energy

4 efficiency improvements, and in October 1989, the Company

5 implemented a Power Cost Adjustment (PCA) mechanism.

6 There have been several temporary adjustments to overall

7 Idaho electric rates, both increases and decreases, over

8 the years associated with that mechanism.

9 Q. Does the Tariff Rider have any impact on

10 the normalized level of Company earnings for its Idaho

11 jurisdiction?

12 A. No. The revenue generated by the Tariff

13 Rider has a matching expense associated with it. The

14 bottom line, or net operating income impact is zero, so

15 there is no earnings impact. The actual management of

16 the program disbursements is done through a balance sheet

17 account.

18 Q. Does the PCA mechanism have any impact on

19 the normalized level of Company earnings for its Idaho

20 jurisdiction?

21 A. No. The PCA mechanism only impacts actual,

22 unadjusted earnings, and those impacts are normalized

23 out, or removed from the pro forma results of operations

24 for the Company's Idaho jurisdiction.

25 Q. What has been the Company's experienced

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1 earnings levels since the rate change associated with

2 Case No. U-1008-256?

3 A. The Company has consistently earned below

4 its last authorized level of 10.95%. As I mentioned

5 earlier, one of my main responsibilities is preparation

6 of a semi-annual jurisdictional electric report that is

7 required in Washington. The Company provides a copy of

8 this report based on its Idaho jurisdiction results to

9 the Idaho Commission Staff.

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1 These reports are prepared on a "Commission Basis."

2 Commission Basis means that rate base includes standard

3 rate base components that have historically been accepted

4 by the Commission for ratemaking. Additionally, the

5 Company's booked results of operations are adjusted to a

6 ratemaking basis by normalizing weather impacts on

7 revenues and power supply and eliminating out-of-period

8 items, nonrecurring items or any other item that would

9 materially distort the test period's results. The final

10 result is a restated rate of return for the reporting

11 period. A historical review of the Company's filings

12 with the Commission show that the Company's electric

13 operations have been earning less than its last

14 authorized rate of return for a number of years. Even

15 though the Company is aware that many things have changed

16 in the financial markets since its last general case in

17 Idaho, a history of the normalized returns that the

18 Company has filed with the Commission will still provide

19 some perspective. Below is that history.

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WWP

1 Q. After a long period of flat general rates,

2 this filing represents a relatively large requested

3 increase. Is there one main issue that contributed to

4 the increase?

5 A. There is no one single item contributing to

6 the magnitude of the requested increase. Obviously, not

7 having had a general rate case for over 12 years has

8 contributed to the rate pressure. Readily identifiable

9 items are customer growth, rate base growth (especially

10 in distribution plant), power supply costs and updated

11 depreciation rates. Also, a recent agreement in

12 principle that settles the long-term negotiations related

13 to relicensing of two of the Company's hydro generating

14 facilities resulted in added costs.

15 Q. How has the Company's customer base changed

16 since the 1985 test year?

17 A. Customer count for the Company's Idaho

18 electric jurisdiction has increased from approximately

19 68,000 to over 99,000 at the end of 1997, or a 46%

20 increase.

21 Q. Doesn't an increase in customer base also

22 mean an increase in total revenues?

23 A. Yes. Assuming the level of revenue per

24 customer stays the same, overall revenues do increase

25 with customer growth. However, as already noted, general

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1 business rates have not increased since 1986, while the

2 expenses associated with serving our customers have been

3 increasing.

4 Q. Has the Company experienced any changes in

5 the level of revenue generated on a per customer basis

6 between the 1985 test year and now?

7 A. Yes. General business revenues per

8 customer have declined by almost 6%, on a normalized

9 basis. Since base rates have remained constant, this

10 indicates energy usage has declined. This will be

11 discussed in more detail by Witness Hirschkorn.

12 Q. Are there other rate pressures associated

13 with the customer growth?

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Falkner, Di 5A
WWP

1 A. Yes. The physical plant known as

2 Distribution plant has increased by over 130%. Using the

3 pro forma information for Idaho electric operations in

4 1985 and now in this filing, on a per customer basis,

5 Distribution plant has risen from $1,283 to $2,052, or a

6 60% increase. With the recent economic growth in the

7 Company's north Idaho service territory, customer growth

8 has been higher in recent years than past years. This

9 results in a higher percentage of total distribution

10 plant being comprised of newer, higher cost plant. Below

11 is a chart that illustrates Distribution plant as well as

12 average customers over the period of years we have been

13 supplying the semi-annual reports to this Commission:

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12 Q. Have there been corresponding increases in

13 Distribution related expenses?

14 A. Yes. Since the last time Idaho electric

15 base rates were changed, distribution expenses, again on

16 a per customer basis, have increased from $99 in 1985 to

17 $147 in 1997, or 48%. This increase illustrates the

18 impact of inflation, more than that of customer growth.

19 Looking at strictly the nominal dollar increase in

20 distribution expense shows an increase of 117% versus a

21 46% increase in actual customer count.

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WWP

1 ALLOCATION PROCEDURES

2

3 Q. Referring to what has been marked as

4 Exhibit No. 10, would you explain what is included in

5 this exhibit?

6 A. Yes. Exhibit No. 10 is an explanation of

7 the allocation procedures used for revenues, expenses and

8 rate base. For ratemaking purposes, the Company must

9 allocate revenues, expenses and rate base between

10 electric and gas services and between Washington, Idaho,

11 Oregon and California jurisdictions where electric and/or

12 gas service is provided.

13 Q. Have allocation procedures changed since

14 the last time the Company changed general electric rates?

15 A. Yes. Since the last time the Company

16 changed general electric rates, the Company acquired

17 natural gas operating properties in Oregon and

18 California. New procedures for allocating common costs

19 and common general plant were developed in conjunction

20 with the Staffs of all four state jurisdictions. The

21 Commission Staff performed a preliminary analysis of the

22 Company's new methodology for assigning and allocating

23 common costs between services and jurisdictions.

24 Q. What was the result of the Staff's

25 preliminary review?

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Falkner, Di 8
WWP

1 A. In a letter to the Company, Staff stated

2 that they believed the new methodology to be a major

3 improvement over the then existing allocation method and

4 that they would not oppose the general methodology when

5 it is proposed in the Company's next rate case. The

6 Staff did note that they will review the actual

7 allocations in a future proceeding and may take exception

8 to or propose minor modifications in the actual

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1 application of the methodology to a particular cost if

2 deemed appropriate. The new methodology was implemented

3 at the start of 1994.

4 Q. Has the Staff had an opportunity to review

5 the actual allocations since they were implemented in

6 1994?

7 A. Yes. The Company has filed reports with

8 the Commission every 6 months on a "Commission Basis," as

9 explained earlier in my testimony. These reports have

10 reflected the new allocation since 1994. And recently,

11 in Case No. WWP-E-98-1, the Commission's investigation

12 into the Company's costs of providing electric service,

13 the Staff reviewed the allocated costs of our Idaho

14 electric operations and the associated allocation

15 methodologies.

16 Q. What was the result of the Staff's review

17 of the Company's allocation methodologies?

18 A. The Staff found that the allocation system

19 is being applied properly and produces the proper

20 allocation of financial data. Further, Staff stated that

21 the Company's rate base is properly allocated between

22 jurisdictions.

23 Q. What information does Exhibit No. 10

24 provide?

25 A. Exhibit No. 10 provides a narrative

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WWP

1 description of the main components of the current

2 procedures utilized in allocating revenue, expense and

3 rate base between services and between jurisdictions

4 within the electric service.

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1 REVENUE REQUIREMENT

2

3 Q. Now, handing you what has been marked as

4 Exhibit No. 11, for identification, would you please

5 outline what is shown in this exhibit?

6 A. Yes. Exhibit No. 11 shows actual and pro

7 forma electric operating results and rate base for the

8 test period for the State of Idaho. Column (b) of page 1

9 of Exhibit No. 11 shows 12 months ended December 1997

10 operating results and components of the

11 average-of-monthly-average rate base as recorded; column

12 (c) is the total of all adjustments to net operating

13 income and rate base; and column (d) is pro forma results

14 of operations, all under existing rates. Column (e)

15 shows the revenue increase required which would allow the

16 Company an opportunity to earn a 9.446% rate of return.

17 Column (f) reflects pro forma electric operating results

18 with the requested increase of $14,223,000.

19 Q. Would you please explain page 2 of Exhibit

20 No. 11?

21 A. Yes. Page 2 shows the calculation of the

22 $14,223,000 revenue requirement at the requested 9.446%

23 rate of return.

24 Q. Would you now please explain page 3 of

25 Exhibit No. 11?

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WWP

1 A. Yes. Page 3 shows the derivation of the

2 net operating income to gross revenue conversion factor.

3 The conversion factor takes into account uncollectible

4 accounts receivable, Commission fees and Idaho State

5 income taxes. Federal income taxes are reflected at 35%.

6 Q. Now turning to pages 4 through 8 of your

7 Exhibit No. 11, for identification, would you please

8 explain what is shown by those pages?

9 A. Yes. Page 4 begins with actual operating

10 results and rate base for the test

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WWP

1 period in column (b). Individual normalizing adjustments

2 that are standard components of our semi-annual reporting

3 to the Commissions begin in column (c) on page 4 and

4 continue through column (q) on page 6. Column (r) on

5 page 6, entitled Restated Total, is the subtotal of all

6 preceding columns. Individual pro forma and additional

7 normalizing adjustments begin in column (PF1) on page 7

8 and continue through column (PF8) on page 8. These

9 adjustments are either refined calculations of

10 adjustments that are usually included as components of

11 our semi-annual reporting, e.g. the Power Supply

12 adjustment, or adjustments that are unique to this

13 general rate filing, e.g. the Hydro Relicensing

14 adjustment. Column (PF9) is the final pro forma

15 operating results and rate base for the test period.

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17 COMMISSION BASIS ADJUSTMENTS

18

19 Q. Would you please explain each of these

20 adjustments, the reason for the adjustment and its effect

21 on test period State of Idaho net operating income and/or

22 rate base?

23 A. Yes. The first adjustment, column (c) on

24 page 4, entitled Deferred FIT Rate Base, reflects the

25 rate base reduction for Idaho's portion of deferred

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Falkner, Di 11
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1 taxes. The adjustment reflects the deferred tax balances

2 arising from accelerated tax depreciation (Accelerated

3 Cost Recovery System, ACRS, and Modified Accelerated Cost

4 Recovery, MACRS), bond refinancing premiums, and

5 contributions in aid of construction. The effect on

6 State of Idaho rate base is a reduction of $48,727,000.

7 Column (d), Deferred Gain on Office Building,

8 reflects the rate base reduction for Idaho's portion of

9 the net of tax, unamortized gain on the sale of the

10 Company's general

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1 office facility. The facility was sold in December 1986

2 and leased back by the Company. The effect on State of

3 Idaho rate base is a reduction of $611,000.

4 Column (e), Colstrip 3 AFUDC Elimination, is a

5 reallocation of rate base and depreciation expense

6 between jurisdictions. In Cause Nos. U-81-15 and

7 U-82-10, the Washington Utilities and Transportation

8 Commission (WUTC) allowed the Company a return on a

9 portion of Colstrip Unit 3 construction work in progress

10 (CWIP). A much smaller amount of Colstrip Unit 3 CWIP

11 was allowed in rate base in Case U-1008-144 by this

12 Commission. The Company eliminated the AFUDC associated

13 with the portion of CWIP allowed in rate base in each

14 jurisdiction. Since production facilities are allocated

15 on the Production/Transmission formula, the allocation of

16 AFUDC is reversed and a direct assignment is made. These

17 amounts are a component of actual results of operations.

18 The effect on State of Idaho net operating income is a

19 decrease of $209,000. The effect of the reallocation on

20 State of Idaho rate base is an increase of $4,071,000.

21 The adjustment in column (f), Colstrip Common

22 AFUDC, is also associated with the Colstrip plants in

23 Montana, and increases rate base. Differing amounts of

24 Colstrip common facilities were excluded from rate base

25 by the WUTC and this Commission until Colstrip Unit 4 was

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1 placed in service. The Company was allowed to accrue

2 AFUDC on the Colstrip common facilities during the time

3 that they were excluded from rate base. It is necessary

4 to directly assign the AFUDC because of the differing

5 amounts of common facilities excluded from rate base by

6 the WUTC and this Commission. In September 1988, an

7 entry was made to comply with a Federal Energy Regulatory

8 Commission (FERC) Audit Exception which transferred

9 Colstrip common AFUDC from the plant accounts to account

10 186. These amounts reflect a direct assignment of rate

11 base for the appropriate average of

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1 monthly averages amounts of Colstrip common AFUDC to the

2 Washington and Idaho jurisdictions. Amortization expense

3 associated with the Colstrip common AFUDC is charged

4 directly to the Washington and Idaho jurisdictions

5 through Account 406. These amounts are a component of

6 the actual results of operations. The effect on State of

7 Idaho rate base is an increase of $1,649,000.

8 The adjustment in column (g), Kettle Falls

9 Disallowance, decreases rate base. The amounts reflect

10 the Kettle Falls generating plant disallowance ordered by

11 this Commission in Case No. U-1008-185. This Commission

12 disallowed a rate of return on $3,009,445 of investment

13 in Kettle Falls. The disallowed investment and related

14 accumulated depreciation are removed. These amounts are

15 a component of actual results of operations. The effect

16 on State of Idaho rate base in a decrease of $1,865,000.

17 Q. Please turn to page 5 and explain the

18 adjustments shown there.

19 A. Column (h), Weatherization and DSM

20 Investment, includes in rate base balances (net of

21 amortization) of weatherization grants, the model

22 conservation program costs and electric demand side

23 management (DSM) program costs upon which AFUCE is no

24 longer being accrued and full amortization was

25 implemented beginning August 1994. These amounts are a

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1 component of actual results of operations. The effect on

2 State of Idaho rate base is an increase of $16,034,000.

3 Q. Would you please explain how energy

4 efficiency-related expenditures impact the revenue

5 requirement in this case?

6 A. Yes. The unamortized balance of energy

7 efficiency management investment incurred prior to 1995

8 is included in the results of operations and becomes a

9 rate base item in the column (h) adjustment just

10 described. DSM expenditures incurred after March 13,

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1 1995 have been and will continue to be offset by revenues

2 from the Company's energy efficiency tariff rider,

3 Schedule 91, and are not included in the revenue

4 requirement.

5 As the Commission is aware, the Company's tariff

6 rider under Schedule 91 is North America's first

7 non-bypassable distribution charge to fund energy

8 efficiency. Approved in Case No. WWP-E-94-12, the tariff

9 rider is a 1.5% surcharge to all rate classes, with the

10 exception of pre-existing special contracts.

11 The tariff rider and the corresponding energy

12 efficiency programs, have been very successful. Over 31

13 million kWh have been saved through programs associated

14 with the rider. The states of California and Montana

15 have since adopted a similar distribution charge as state

16 law.

17 The Commission approval in Case WWP-E-94-12, and

18 reiterated in Case WWP-E-98-9, requires that the Company

19 demonstrate the prudence of the Company's programs and

20 expenditures at the time of a general rate case.

21 Q. Is the Company requesting any DSM-related

22 finding in this case?

23 A. Yes. The Company requests that the

24 Commission issue a finding that the energy efficiency

25 revenues collected under Schedule 91 have been prudently

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1 expended through the energy efficiency programs offered

2 under Schedule 90.

3 Page 1 of Exhibit No. 12 provides the kilowatt

4 hours saved by program. Page 2 of this exhibit shows the

5 amount of Idaho jurisdictional revenue collected under

6 Schedule 91 and related expenditures incurred under

7 Schedule 90. Exhibit No. 13 summarizes the

8 cost-effectiveness and methodology used to determine the

9 prudence of the programs.

10 Q. Please summarize the Company's conclusions.

11 A. The Company's expenditure of tariff rider

12 revenue has been reasonable and

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1 prudent. Eighteen programs covering all customer classes

2 have been offered with a total savings of over 31 million

3 annual kWhs. The cost per saved kilowatt hour has

4 averaged 1.4 cents per kWh on a 15 year levelized basis.

5 The avoided costs during this similar period has averaged

6 3.1 cents per kWh.

7 From a qualitative perspective, the rider and

8 programs have been very successful. The Company has

9 demonstrated that meaningful conservation programs can be

10 sustained in a more competitive electric industry

11 environment. The fact that the tariff rider has been

12 copied elsewhere validates this point. Participating

13 customers have benefited through lower bills.

14 Non-participating customers have benefited from the

15 Company having acquired low cost resources as well as

16 maintaining the energy efficiency message and

17 infrastructure for the benefit of our service territory.

18 Q. How are the energy efficiency programs

19 organized?

20 A. The programs are organized around an

21 expertise-based technical assistance program portfolio.

22 This is a shift from the past focus on grant-dispensing.

23 This approach focuses on educating the customer about the

24 benefits of energy efficiency, providing a third party

25 review, and outlining potential savings of the project.

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1 Since the early 1990's, the Company's energy

2 efficiency programs have been at the leading edge of

3 program delivery. These programs have received national

4 recognition.

5 Q. What customer classes can benefit from

6 these programs?

7 A. The Company's programs are delivered across

8 a full customer spectrum. Virtually all customers have

9 had the opportunity to participate and a great many have

10 directly benefited from the program offerings. All

11 customers have indirectly benefited through enhanced

12 cost-efficiencies of both the public and private sectors

13 as a result of this

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1 portfolio.

2 For example, educational institutions such as

3 public school districts, the Lewis Clark State College

4 and the University of Idaho have saved significant energy

5 and resource costs. Furthermore, Idaho customers in

6 several strategic and highly competitive industries have

7 cost-effectively implemented energy efficiency projects.

8 These, in turn, have economically benefited these

9 industries and, as primary industries, this benefits the

10 entire economic region.

11 Q. Has there been ongoing review of the

12 Company's programs?

13 A. Yes. The Company has regularly convened a

14 stakeholders forum, now the External Energy Efficiency

15 Board and previously known as the DSM Opportunities

16 Group. These meetings have included customer

17 representatives, Commission staff members, and

18 individuals from the environmental communities. These

19 stakeholder meetings have reviewed each program as well

20 as the underlying cost-effectiveness tests and results.

21 Q. Please continue with your explanation of

22 the adjustments on page 5.

23 A. The adjustment in column (i), Customer

24 Advances, decreases rate base for moneys advanced by

25 customers for line extensions as they will most likely be

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1 recorded as contributions in aid of construction at some

2 future time. The effect on State of Idaho rate base is a

3 decrease of $573,000.

4 The adjustment in column (j), Settlement Exchange

5 Power, reflects the net operating income requirement

6 associated with the recovery of the allowed portion of

7 the Company's investment in Settlement Exchange Power.

8 The allowed recovery level was approved by Order No.

9 20208 in Case No. 1008-204 on January 9, 1986. Net

10 amortization expense (net of deferred return and carrying

11 cost on deferred return) and deferred FIT expense

12 recorded

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1 during the test period are removed and the net operating

2 income requirement approved in Case U-1008-204 is

3 incorporated. These amounts are a component of actual

4 results of operations. The effect on State of Idaho net

5 operating income is a reduction of $1,010,000.

6 The column marked by a dash, and immediately

7 following column (j), subtotals columns (b) through (j)

8 and represents actual operating results and rate base

9 plus the standard rate base adjustments that are included

10 in Commission Basis reporting, but not generally

11 calculated in the Company's monthly jurisdictional

12 Results of Operations reports.

13 Column (k), Eliminate Franchise Fees, eliminates

14 the revenues and expenses associated with local franchise

15 fees which the Company is allowed to pass through to its

16 Idaho customers. The adjustment eliminates any timing

17 mismatch that exists between the revenues and expenses by

18 eliminating the revenues and expenses in their entirety.

19 Franchise fees are passed through on a separate schedule

20 which is not part of this proceeding. The effect of this

21 adjustment is to decrease State of Idaho net operating

22 income by $10,000.

23 Column (l), Property Tax, restates the 1997 test

24 period accrued levels of property taxes to the actual

25 amounts. The effect of this particular adjustment is to

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1 decrease Idaho net operating income by $107,000.

2 Q. Please turn to page 6 and explain the

3 adjustments shown there.

4 A. Column (m), Uncollectible Expense, restates

5 the accrued expense to the actual level of net write-offs

6 for the test period. The effect of this adjustment is to

7 decrease Idaho net operating income by $41,000.

8 Column (n), Regulatory Expense Adjustment,

9 restates booked 1997 regulatory expense to reflect the

10 IPUC assessment rates applied to revenues for the test

11 period. The

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1 effect of this adjustment is to increase Idaho net

2 operating income by $18,000.

3 Column (o), Injuries and Damages, is a restating

4 adjustment that replaces the accrual with the six year

5 rolling average of actual injuries and damages payments

6 not covered by insurance. A six year rolling average and

7 the reserve method of accounting for injuries and

8 damages, net of insurance proceeds, is a practical

9 methodology to deal with these normal utility operating

10 expenses that happen to occur on an irregular basis and

11 differ markedly in materiality. As a result of the

12 WUTC's Order in Docket No. U-88-2380-T, the Company

13 changed to the reserve method of accounting for injuries

14 and damages not covered by insurance for both its

15 electric and gas systems and conformed the methodology in

16 both jurisdictions. The effect of this adjustment is to

17 decrease Idaho net operating income by $80,000.

18 Q. Does the Company include the effects of

19 extraordinary circumstances such as the Firestorm of 1991

20 and the Ice Storm of 1996 in the regulatory accrual for

21 injuries and damages?

22 A. Yes. Both events, net of insurance

23 proceeds, are included in the adjustment that is filed in

24 the Commission Basis reporting. The amounts for both

25 events are directly assigned to jurisdictions. Firestorm

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1 costs are assigned to the Washington jurisdiction and do

2 not impact Idaho net operating income. The Ice Storm

3 component is also directly assigned to jurisdictions and

4 impacts both states.

5 Q. Does the Company propose to handle all

6 storm damage costs through the injuries and damages

7 accrual?

8 A. No. Some level of storm damage related

9 expense is contained in virtually every test period for

10 the Company and no changes are being proposed to adjust

11 those test

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1 period costs. However, the extraordinary storm damage

2 costs included in the injuries and damages accrual, while

3 not regular occurrences, are legitimate expenditures that

4 do impact a utility's operations from time to time. A

5 six year rolling average of these non-insured costs of a

6 utility is a reasonable vehicle for recognizing the

7 validity of these expenditures, while at the same time

8 "smoothing" the potential recovery of these costs over a

9 period of time.

10 Q. Please continue your explanation of the

11 adjustments found on page 6.

12 A. Column (p), entitled FIT, is required to

13 reflect the appropriate level of federal income tax

14 expense for the test period. This adjustment removes the

15 effect of certain Schedule M items, matches the

16 jurisdictional allocation of other Schedule M items to

17 related Results of Operations allocations, eliminates any

18 prior period income tax expense, and amortizes audit

19 adjustment payments over a two year period. The normal

20 audit cycle is an audit every two years covering two

21 years of returns. This adjustment also reflects the

22 proper level of deferred tax expense for the test period.

23 The effect of this adjustment, all based upon a Federal

24 tax rate of 35%, is to increase Idaho net operating

25 income by $343,000.

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1 Column (q), entitled Idaho PCA, removes the

2 effects of the financial accounting for the Idaho Power

3 Cost Adjustment (PCA). The PCA normalizes and defers

4 certain power supply costs on an ongoing basis between

5 general rate filings. When the deferral balance reaches

6 a certain trigger level, the balance is either returned

7 (refunded) or charged (surcharged) to customers through a

8 special temporary tariff. Revenue adjustments due to the

9 special tariff and the power cost deferrals affect actual

10 results of operations and need to be eliminated to

11 produce a normal period. Actual revenues and power

12 supply costs are normalized in adjustments to be

13 discussed later. The effect of this adjustment is to

14 increase

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1 Idaho net operating income by $2,455,000.

2 Column (r), entitled Restated Total, subtotals all

3 the preceding columns (b) through column (q), exclusive

4 of the previously discussed subtotal column. These

5 totals represent actual operating results and rate base

6 plus the majority of the standard normalizing adjustments

7 that the Company includes in its semi-annual Commission

8 Basis reports. Notable exceptions to the list of

9 standard Commission Basis adjustments, up to this point,

10 are the first three pro forma adjustments (PF1-PF3).

11 Those being the power supply adjustment, the Potlatch

12 adjustment and the revenue adjustment. Those

13 adjustments, which will be discussed later by myself and

14 Witnesses Hirschkorn and Norwood, have been produced in

15 more detail and were based upon a different pro forma

16 period than were originally prepared for the Commission

17 Basis reports.

18

19 PRO FORMA AND ADDITIONAL NORMALIZING ADJUSTMENTS

20

21 Q. Please turn to page 7 and explain the

22 significance of the 8 columns subsequent to column (r)

23 that begin on that page in your Exhibit No. 11.

24 A. Certainly. All adjustments subsequent to

25 column (r) are signified by a PF with an identifying

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1 digit, 1 through 8. These adjustments bring the

2 operating results and rate base to the final pro forma

3 level for the test year. They contain the standard pro

4 forma and normalizing adjustments included in a general

5 rate filing, but not generally included in, or in more

6 detail than the Company's Commission Basis filings.

7 Additionally, they include adjustments that recognize the

8 jurisdictional impacts of material items that will impact

9 the pro forma operating period.

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1 Q. Please continue with your explanation of

2 the adjustments on page 7.

3 A. Column (PF1), entitled Pro Forma Power

4 Supply-7/99-6/00, was made under the direction of

5 Mr. Norwood and is explained in detail in his testimony.

6 This adjustment normalizes power supply related revenue

7 and expenses to reflect the twelve month period July 1,

8 1999 through June 30, 2000. The effect of the power

9 supply adjustments as shown in Mr. Norwood's Exhibit

10 No. 6, which is presented on a system basis, decreases

11 Idaho net operating income by $9,918,000.

12 Column (PF2), entitled Pro Forma

13 Potlatch-7/99-6/00, synchronizes portions of the Potlatch

14 Contract revenues that are dependent upon non-firm rates

15 with the non-firm rates determined by the Company's

16 dispatch model and utilized in the Pro Forma Power Supply

17 adjustment. Additionally, monthly service charges are

18 escalated to the charge that would be in place during

19 that period. The effect of this adjustment is to

20 increase Idaho net operating income by $894,000.

21 Column (PF3), Pro Forma Revenue Adjustment, is a

22 3-fold adjustment taking into account known and

23 measurable changes that include revenue normalization,

24 weather normalization and an unbilled revenue

25 calculation. It encompasses correction of rate schedule

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1 shifts, repricing for approved tariff changes that will

2 be in place in the pro forma test period that were not in

3 place in the historical test period. Also, it includes

4 an increase in electric revenues due to the process of

5 normalizing weather sensitive electric kWh sales, which

6 in this case, eliminates the effect of warmer than

7 historical normal temperatures. Witness Hirschkorn is

8 sponsoring this adjustment. The effect of this

9 particular adjustment is to increase Idaho net operating

10 income by $1,639,000.

11 Column (PF4), Pro Forma Miscellaneous Adjustments,

12 eliminates an out-of-period

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1 expense, includes a contingency for a settlement and

2 properly reclassifies certain revenues that had been

3 recorded in Other Revenues for tracking purposes to

4 General Business Revenues. The effect of this adjustment

5 is to decrease Idaho net operating income by $110,000.

6 Column (PF5), Pro Forma Labor/Benefit Adjustment,

7 reflects known and measurable changes to salary levels as

8 well as normalization of test period benefit costs. The

9 Labor calculation consists of two components. The first

10 component adjusts for wage and salary increases which

11 occurred in March 1997 as if the changes were in effect

12 for the entire test period. The second component adjusts

13 the restated 1997 level of wages for increases granted in

14 March 1998. The benefit portion of the adjustment

15 reduces total benefits costs. The amount loaded onto

16 labor charges through the estimated loading rate during

17 the test period produced an expense level higher than the

18 actual amount of employee benefits for the period. The

19 combined effect of this adjustment results in a reduction

20 to Idaho net operating income of $200,000.

21 Q. Please turn to the final page of Exhibit

22 No. 11, page 8, and continue with your explanation of the

23 adjustments.

24 A. Column (PF6), Pro Forma Depreciation

25 Adjustment, reflects an increase in depreciation expense

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1 due to the utilization of new depreciation rates that

2 were the result of a detailed depreciation study

3 performed by a consultant from Deloitte & Touche, LLP.

4 This adjustment also eliminates the out-of-period annual

5 depreciation expense true-up adjustment for 1996 and adds

6 in the true-up for 1997 that was recorded in 1998. The

7 effect of this adjustment is to decrease Idaho net

8 operating income by $1,573,000 and to decrease Idaho rate

9 base by $807,000.

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1 Q. When was the last time the Company changed

2 its depreciation rates?

3 A. The last time the Company changed

4 depreciation rates was January 1, 1990.

5 Q. Is the Company proposing different

6 depreciation methodologies in this case than what was

7 used in 1990?

8 A. No. The change in depreciation rates

9 determined by the consultant, and the resultant change in

10 expense, is due to updated information determined through

11 study and analysis of historical retirement experience,

12 salvage and cost of removal experience and determination

13 of updated unit remaining lives and net salvage factors,

14 not new methodologies. It should be noted that the

15 Company continues to employ the Sinking Fund methodology

16 for determining the depreciation expense of its hydro

17 electric generating facilities.

18 Q. What were the changes in depreciation rates

19 that were recommended as a result of the study?

20 A. Following is a table that shows the

21 existing rates and the recommended rates:
Depreciation Rates
22 Existing% Recommended%
Functional Electric Group
23 Steam Production Plant 3.12 3.38
Hydraulic Production Plant 1.04 1.58
24 Other Production Plant 4.18 2.36
Transmission Plant 2.41 2.88
25 Distribution Plant 2.27 2.45
General Plant 6.00 12.24
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1 Q. What does that represent in terms of a

2 percentage increase in depreciation expense?

3 A. By utilizing the new rates recommended in

4 the study and applying them to

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1 system electric plant balances as of December 31, 1996,

2 depreciation expense increased by approximately 19%, with

3 Production plant and General plant constituting the

4 majority of the increase.

5 Q. Can you summarize the findings and

6 recommendations of the depreciation study using the

7 functional groups listed above?

8 A. Yes. The composite rate for electric

9 property under the study changed from 2.46% to 2.98%. As

10 a group, life changes were mostly increases. Net salvage

11 changes were mostly decreases due to decreased salvage

12 and increased cost of removal. The relationship of

13 increased asset life and net salvage decreases is

14 expected due to the fact that cost of removal is

15 sensitive to price level changes that reflect labor

16 costs, while the salvage value of an asset will

17 inherently decrease as its age increases.

18 A primary cause of the increase in Hydraulic

19 Production Plant was the recommendation to update the

20 interest rate included in the Sinking Fund calculation

21 from the old rate of 6% to 9% to better reflect the

22 Company's current cost of capital. Transmission and

23 Distribution plant accounts experienced increased levels

24 of negative net salvage. Steam Production plant accounts

25 increased due to new investment which has a shorter

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1 recovery period than original installations and increased

2 negative net salvage. Other Production plant decreased

3 due to increased service lives. General plant increased

4 due to changes in average service lives reflecting

5 technological obsolescence. Specifically, Account 391.1,

6 Computer Equipment lives were reduced from 8 to 5 years

7 to more appropriately reflect asset turnover. Account

8 397, Communication Equipment lives were reduced from 18

9 to 10 years to better reflect the type of asset being

10 installed.

11 Q. What are the Company's plans with regards

12 to management of its installed

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1 personal computer base?

2 A. There is little doubt that computer

3 technology is rapidly changing. The Company is planning

4 to enter into a lease agreement with a large computer

5 vendor to obtain office computers through a 3 year lease

6 program and rotate new computers at the end of each

7 individual lease.

8 Q. Why is the recommended average life for

9 Account 391.1-Computer Equipment, as a result of this

10 depreciation study, 5 years, and not the 3 year life

11 being utilized in the new lease program?

12 A. Personal computers are not the only

13 equipment in this category. Other equipment are

14 printers, control boxes, modems, etc. An average of 5

15 years is a better reflection of the overall assets in

16 this account. It is expected that another depreciation

17 study will be performed after December 31, 2001 and

18 technology sensitive depreciable assets will be

19 re-evaluated at that time.

20 Q. What impact did normalizing the annual

21 expense true-up adjustments have on depreciation expense?

22 A. Properly recording the true-up adjustments

23 in their respective reporting periods served to slightly

24 reduce recorded expense for the 1997 test year.

25 Q. Why are new depreciation rates being

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1 proposed in this general electric filing?

2 A. Accounting theory requires matching of

3 expenses with either consumption or revenues to ensure

4 that financial statements reflect results of operations

5 as accurately as possible. The matching principle of

6 financial accounting is often referred to as the "cause

7 and effect" principle. Because utility revenues are

8 determined through regulation, changes

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1 in asset consumption are not automatically reflected in

2 revenues until regulated revenues are adjusted to reflect

3 the changes in asset consumption. Consumption of utility

4 assets must be measured directly by conducting a book

5 depreciation study to accurately determine mortality

6 characteristics. Matching is a an element of regulatory

7 philosophy that addresses intergenerational equity.

8 Intergenerational equity means costs are borne by the

9 generation of customers that caused them to be incurred,

10 not by a later generation. This matching concept is one

11 principle that can be used to ensure that charges to

12 customers reflect the actual costs of providing service.

13 Q. Could you please state again the effect

14 this adjustment has on the State of Idaho results of

15 operations?

16 A. Yes. The effect of this adjustment

17 decreased Idaho net operating income by $1,573,000 and

18 after employing average of monthly average calculations

19 to the increased level of book depreciation expense,

20 changes to accumulated depreciation and deferred Federal

21 income tax reduced Idaho rate base by $807,000.

22 Q. Please continue with your explanations of

23 the adjustments on page 8 of your Exhibit No. 11.

24 A. Column (PF7), entitled Pro Forma

25 Relicensing Cost Adjustment, reflects inclusion of the

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1 annual operating expense portions in pro forma results of

2 operations of a soon to be signed agreement that settles

3 all stakeholder issues associated with relicensing of

4 certain of the Company's hydroelectric facilities on the

5 Clark Fork River.

6 Q. Can you provide a brief background of this

7 relicensing process?

8 A. Yes. The Company will file a license

9 application in February 1999 for a new federal license

10 for the Noxon Rapids and the Cabinet Gorge Projects,

11 collectively

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1 referred to as the "Clark Fork Projects." Cabinet Gorge

2 and Noxon Rapids were licensed for 50 years beginning in

3 1951 and 1955, respectively. In 1995 the Company amended

4 the Noxon Rapids license to accelerate its date of

5 expiration from 2005 to 2001 to allow for simultaneous

6 relicensing of both projects.

7 The Company began strategic planning for the

8 relicensing of the Clark Fork Projects in 1992. After

9 reviewing many relicensing proceedings and the

10 difficulties associated with the traditional FERC

11 process, the Company developed and embarked on a unique

12 collaborative process referred to as the Living

13 LicenseTM. The goal of this collaborative process was to

14 facilitate the negotiation of an effective settlement

15 agreement that would give the Company the greatest

16 opportunity to limit its costs over the term of a new

17 license.

18 The collaborative process began in mid-1996 with a

19 meeting of all stakeholders and the use of neutral

20 facilitators. The organizations in the collaborative

21 process became known as the Clark Fork Relicensing Team.

22 The Team also formed five technical work groups to

23 resolve very detailed and specific resource issues.

24 Q. Who were the stakeholders that made up this

25 group?

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1 A. The group included over 100 representatives

2 from nearly 40 organizations, including federal and state

3 agencies and local governments from Idaho and Montana,

4 five American Indian tribes, non-government

5 organizations, conservation groups, property owners and

6 the Company.

7 Q. Did this collaborative process prove

8 successful?

9 A. Yes. The process was a significant

10 departure from traditional FERC relicensing procedures

11 and produced a very successful negotiation process. From

12 a tangible standpoint, the process produced an agreement

13 among the wide ranging stakeholders, the

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1 Clark Fork Settlement Agreement, that effectively settles

2 all merit issues raises in the process. The Clark Fork

3 Agreement is the first comprehensive settlement every

4 reached in a major relicensing before the application was

5 filed, and would represent the first time in the nation

6 that major facilities were ever relicensed on the

7 regulatory schedule. In addition, the Clark Fork

8 Settlement Agreement should ensure a relatively

9 streamlined review of the actual FERC application, and a

10 high level of certainty on its ultimate outcome. The

11 Clark Fork Collaborative Relicensing Process is now

12 nationally recognized as the model for FERC's adoption of

13 the "collaborative alternative" among alternative

14 approaches to hydropower relicensing.

15 As part of the Clark Fork Settlement Agreement,

16 the Company has committed to implement its provisions

17 beginning in March of 1999; two years before the present

18 licenses expire.

19 Q. Since the initial FERC licenses expire in

20 2001, why are payments under the Clark Fork Settlement

21 Agreement scheduled to begin in 1999?

22 A. Early implementation of the settlement

23 agreement measures became the Company's greatest point of

24 leverage in negotiating an agreement among parties at a

25 much lower cost to the Company than certain agencies had

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1 the unilateral authority to require. While a lower cost

2 agreement was the primary objective of the Company in

3 early implementation, other parties were motivated by the

4 benefits to the project's associated natural resources,

5 which would now occur earlier than in the traditional

6 regulatory process. This was an especially important

7 consideration for the Company and others in measures

8 related to bull trout, which was recently listed as

9 "threatened" under the Endangered Species Act.

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1 Q. What has the Company done with the costs of

2 the collaborative process?

3 A. The costs of the collaborative process to

4 date have been capitalized in FERC account 302,

5 Franchises and Consents. Through October 1998, these

6 costs totaled $13,443,000 on a system basis, including

7 associated Allowance for Funds Used During Construction

8 (AFUDC).

9 Q. What are the costs associated with

10 implementation of the Clark Fork Settlement Agreement?

11 A. Estimated total annual ongoing license

12 implementation costs are $4,796,500 on a system basis.

13 Of that amount, $2,042,000 has been determined to be

14 capital expenditures and $2,754,500 has been determined

15 to be Operation and Maintenance. (O&M). The O&M amount

16 is reduced by $736,180 of current existing administrative

17 costs, to produce an incremental O&M amount of

18 $2,018,000.

19 Q. When are these costs scheduled to begin and

20 over what term will the agreement be in effect?

21 A. As stated above, these costs are scheduled

22 to begin in March of 1999 and will occur annually over

23 the life of the new FERC licenses. The actual costs in

24 any year over the course of the license will vary

25 depending upon the level of treatment of the issues and

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1 the impact of new issues. The parties to the Settlement

2 Agreement will request that FERC provide the Company a 45

3 year term of license, which is lengthier than is FERC's

4 practice in relicensing.

5 Q. Has an analysis been performed that

6 indicates that the total cost to the Company of entering

7 into a settlement agreement is prudent and reasonable?

8 A. Yes. The Company evaluated many factors to

9 estimate a range of likely

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1 relicensing costs that might eventually be imposed on the

2 Company and considered what was reasonable given the

3 value of the projects to our customers and the resource

4 issues. Those factors included the size of the projects,

5 the complexity and difficulty of the issues, the

6 interests of the participating agencies and

7 organizations, the regulatory authority of the parties to

8 impose unilateral license terms and conditions, FERC's

9 decisions in license orders in similar cases, costs

10 imposed on other licensees, costs of protracted license

11 proceedings and the likelihood of near-term regulatory or

12 rule changes.

13 The final settlement agreement costs reflect the

14 combination and costs of measures required to solve the

15 issues in a way that allowed the Company to preserve

16 nearly all of the project's operating flexibility and

17 their competitive market position.

18 Q. How is the Company proposing that these

19 costs, the capitalized process costs and the annual

20 settlement amounts, be handled for ratemaking?

21 A. The Company is proposing that process costs

22 be amortized over the expected 45 year license request.

23 This produces an annual amortization for the process

24 costs of $298,700 on a system basis. Additionally, the

25 Company is requesting that the scheduled incremental O&M

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1 portion of the Clark Fork Settlement Agreement be

2 included for recovery at the levelized amount of

3 $2,108,000 on a system basis. Both costs are to be

4 allocated based upon the Production/Transmission formula.

5 Q. What is the of effect this adjustment on

6 test period State of Idaho net operating income and/or

7 rate base?

8 A. The effect on State of Idaho net operating

9 income is a decrease of $491,000 and an increase in rate

10 base of $4,175,000.

11 Q. Could you please continue with your

12 explanations of the remaining columns

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1 on page 8 of Exhibit No. 11?

2 A. Yes. Column (PF8), entitled Pro Forma Debt

3 Interest, restates debt interest using the Company's pro

4 forma weighted average cost of debt, as outlined in the

5 testimony and exhibits of Witness Avera and applied to

6 Idaho's pro forma level rate base, plus construction in

7 progress produces a pro forma level of tax deductible

8 interest expense. The Federal income tax effect of the

9 restated level of interest for the test period increases

10 Idaho net operating income by $326,000.

11 Column (PF9), Pro forma Total, reflects total 1997

12 pro forma results of operations and rate base consisting

13 of 1997 actual results and the total of all adjustments.

14 Q. Referring back to page 1, line 42, of

15 Exhibit No. 11, for identification, what was the actual

16 and pro forma electric rates of return realized by the

17 Company during the test period?

18 Q. For the State of Idaho, the actual test

19 period rate of return was 8.548%, below the last

20 authorized rate of return of 10.95%. The test period

21 pro forma rate of return is 6.940% under present rates.

22 Thus, the Company does not, on a pro forma basis for the

23 test period, realize the 9.446% rate of return requested

24 by the Company in this case.

25 Q. By way of summary, could you please review

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1 the different rates of return that you have presented in

2 your testimony?

3 A. Yes. Basically, there are three different

4 rates of return ("ROR") discussed previously. The

5 actual ROR earned by the Company during the test period,

6 the Pro Forma ROR determined in my Exhibit No. 11 and the

7 requested ROR. For convenience of comparison, please

8 refer to the following graph:

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1

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6 (Chart contained in hard copy of transcript.)

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14 Q. How much additional net operating income

15 would be required for the State of Idaho electric

16 operations to allow the Company an opportunity to earn

17 its proposed 9.446% rate of return on a pro forma basis?

18 A. The net operating income deficiency amounts

19 to $9,035,000, as shown on line 5 of page 2 of Exhibit

20 No. 11. The resulting revenue requirement is shown on

21 line 7 and amounts to $14,223,000, or an increase of

22 11.56% over pro forma general business revenues.

23 Q. Does that conclude your direct testimony?

24 A. Yes, it does.

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1 I. INTRODUCTION

2 Q Please state your name, business address,

3 and present position with Avista Corp.?

4 A My name is Don M. Falkner. My business

5 address is East 1411 Mission Avenue, Spokane, Washington.

6 I am employed by Avista Corp. (Company) as a Senior Rate

7 Accountant.

8 Q Have you previously provided direct

9 testimony in this Case?

10 A Yes. My testimony covered accounting and

11 financial data in support of the Company's need for the

12 proposed increase in rates. I explained pro formed

13 operating results including expense and rate base

14 adjustments made to actual operating results and rate

15 base.

16 Q Are you sponsoring any Exhibits with this

17 testimony?

18 A Yes. I am sponsoring Exhibit No. 24, which

19 consists of Schedules DMF-1, DMF-2 and DMF-3.

20 Q What is the scope of your rebuttal

21 testimony in this proceeding?

22 A My rebuttal testimony will address proposed

23 adjustments to depreciation, Hydro Relicensing Costs,

24 Injuries and Damages, DSM Interest and Miscellaneous

25 General Expenses as proposed by Staff witnesses

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Falkner, Di-Reb 1
Avista

1 Ms. Stockton, Mr. Lansing, Mr. Lobb and Mr. Anderson and

2 Potlatch witness, Mr. Peseau.

3 II. DEPRECIATION EXPENSE

4 Q Starting on page 16, line 21, of

5 Mr. Peseau's direct testimony, he states, "...We must

6 keep in mind that the request (depreciation increase) is

7 merely to change accounting to increase Avista's cash

8 flow. None of the categories of plant in service listed

9 on Page 23 of Mr. Falkner's testimony has in any way had

10 their performance, economic

11

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17

18

19

20

21

22

23

24

25

631

Falkner, Di-Reb 1A
Avista

1 value or other attributes changed. Avista has not, and

2 will not, incur any different real cash expense

3 obligation as a result of its depreciation study. The

4 Company simply wants to raise rates to recover its

5 original plant investment sooner to increase today's

6 shareholder profit." Do you agree with this contention?

7 A Not at all. First of all, there is no

8 "change of accounting" being suggested at all. The

9 Company is continuing its universally accepted standard

10 accrual accounting concept for mass-asset accounting

11 procedures, which includes depreciation expense, and is

12 simply revising its estimate of the apportionment of some

13 of its long-lived assets based upon a detailed study

14 performed by a depreciation expert from an international

15 professional accounting firm. As to the suggestion that

16 the depreciation revision is "simply to increase Avista's

17 cash flow," that is an untrue and unsupported statement.

18 It should be pointed out that any change in the Company's

19 revenue requirement in the state of Idaho ultimately

20 approved by this Commission will impact the Company's

21 cash flow, whether it be related to depreciation expense

22 or some other expense or revenue category. Not only

23 utilities, but virtually all companies, periodically

24 review the estimates included in their determination of

25 periodic net operating income and refine and adjust those

632

Falkner, Di-Reb 2
Avista

1 estimates when necessary. This is such a standard

2 accounting activity that the Financial Accounting

3 Standards Board ("FASB") specifically differentiates

4 between a change in accounting practice or procedure and

5 a change in an accounting estimate. As I already stated

6 previously, Mr. Peseau incorrectly characterizes the

7 proposed depreciation rate revisions as a "change in

8 accounting," when it is in actuality, a "change in

9 accounting estimate" that is expected to occur

10 periodically.

11 Q If the depreciation expense revisions are

12 approved by this Commission, will

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19

20

21

22

23

24

25

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Falkner, Di-Reb 2A
Avista

1 shareholder profits increase?

2 A Absolutely not. The depreciation rates

3 that are ultimately approved for inclusion in the

4 Company's revenue requirement will be matched by an

5 associated increase in the Company's recorded book

6 depreciation. The result will neither increase nor

7 decrease the Company's net operating income. Aside from

8 some timing differences, the depreciation expense

9 included in revenues will match the depreciation expense

10 recorded as an expense with the result netting to zero

11 for "shareholder profits." Accordingly, Mr. Peseau's

12 statement is simply inaccurate.

13 Q On Page 17, starting on line 10, Mr. Peseau

14 suggests that depreciation rates of electric utilities

15 throughout the U.S. have been too high for several years

16 due to the sale of some utility assets being made for

17 amounts in excess of net book value. Later, on Page 18,

18 starting on line 2, Mr. Peseau suggests that, "A good

19 test of proper depreciation rates and levels is to

20 compare the market value of these assets, as measured by

21 sales price, to the depreciated book value of these

22 assets." Do you agree with these contentions?

23 A No. Historical cost based accounting,

24 accrual accounting and depreciation expense are bedrock

25 principles of Generally Accepted Accounting Principles

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Falkner, Di-Reb 3
Avista

1 and are also embraced by the FERC in its guidelines

2 established for regulatory accounting. Accounting for

3 long-lived assets based on market value is not.

4 Depreciation is the recognition that some consumption of

5 the economic benefit of a long-lived asset is occurring.

6 Reasonable estimates need to be made of this consumption.

7 Specifically, FASB Statement of Concepts No.5, in

8 paragraph 86 (c) states that, "Some expense, such as

9 depreciation and insurance, are allocated by systematic

10 and rational procedures to the periods during which the

11 related assets are expected to provide benefits."

12 Mr. Peseau attempts to associate some sales of

13

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19

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22

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24

25

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Falkner, Di-Reb 3A
Avista

1 electric utility assets, specifically generation assets,

2 as his main support for not allowing a change in the

3 Company's depreciation rates. Mr. Peseau does not submit

4 any evidence nor is there any authoritative source that I

5 know of that utilizes estimated market value as a "good

6 test" of depreciation rates.

7 Depreciation is systematic recognition and

8 recovery of previously expended funds. Current valuation

9 is not a component of the depreciation decision. If

10 market value is to be taken into consideration in

11 regulatory decisions regarding rate recovery, as

12 Mr. Peseau is suggesting, and one accepts the contention

13 that the net book value of electric utility assets

14 understates their market value, shouldn't then utility

15 rate base for these same assets be increased to reflect

16 "true" value of the common equity investment made by the

17 Company?

18 Q Does Mr. Peseau offer any real evidence

19 that the Company's recommended increase in depreciation

20 rates is inappropriate?

21 A No. Mr. Peseau offered a single article

22 published in Public Utilities Fortnightly and an exhibit

23 from the merger proceeding of a Nevada utility trying to

24 support its claim that it can divest its generation

25 assets for more than book value. Such information is not

636

Falkner, Di-Reb 4
Avista

1 evidence and has no bearing on the Company's

2 determination of appropriate depreciation rates.

3 Mr. Peseau also mentions, on Page 19, line 5 of his

4 direct testimony, only that his firm participated in some

5 study that included "review" of an Edison Electric

6 Institute survey of U.S. depreciation rates, but the

7 study apparently is proprietary and was not even included

8 as evidence in this case. This leaves the Commission

9 only with Mr. Peseau's bald assertions, but with no

10 evidentiary record.

11 Q Is the Company only proposing changes to

12 the depreciation of its generation and production assets?

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19

20

21

22

23

24

25

637

Falkner, Di-Reb 4A
Avista

1 A No. The depreciation study performed by

2 Deloitte and Touche that is the basis for the Company's

3 requested change in depreciation rates, reviewed all

4 asset categories and recommended rate revisions (some

5 upward and some downward) for all main accounts. The

6 proposed increase for production plant makes up less than

7 30% of the Company's proposed depreciation increase.

8 Q Did the Commission Staff perform any kind

9 of review of the Company's support for the proposed

10 depreciation changes?

11 A Yes. On two separate occasions, Mr. Syd

12 Lansing of the Commission Staff, visited the Company

13 offices and spent considerable time questioning internal

14 staff responsible for maintaining the Company's

15 depreciation records and spent days reviewing the

16 detailed workpapers and calculations that supported the

17 final recommendations of the depreciation study.

18 Q Mr. Lansing is recommending adjustments to

19 the Company's depreciation request that serve to reduce

20 the overall request. Do you agree with his adjustments?

21 A Yes. I discussed in some detail, the

22 adjustments being sponsored by Mr. Lansing with the

23 depreciation consultant who prepared the Company's

24 depreciation study. Based upon that discussion, I agree

25 with Mr. Lansing's adjustments. We of course have no

638

Falkner, Di-Reb 5
Avista

1 issue with the portion of the adjustment that correctly

2 applies the new rates to the proper test year basis.

3 Additionally, even though the consultant still feels his

4 original recommendations are appropriate, he agrees with

5 Mr. Lansing's statement, as stated on page 5, line 13, of

6 His direct testimony, "There are always areas of judgment

7 that fall within a range of reasonableness in making

8 these projections." With that said, we find

9 Mr. Lansing's proposal regarding adjustments to

10 transmission and distribution expense

11

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20

21

22

23

24

25

639

Falkner, Di-Reb 5A
Avista

1 reasonable.

2 Q On page 7, starting on line 8, Mr. Lansing

3 notes that there is another adjustment to depreciation

4 expense proposed by another Staff witness. Can you

5 comment on that?

6 A The Company does not accept that

7 adjustment. Company witness Brian Hirshkorn is

8 addressing that proposed adjustment in his rebuttal

9 testimony.

10 III. HYDRO RELICENSING COSTS

11 Q Staff witness, Mr. Lobb, on page 18,

12 starting on line 5 of his direct testimony, and going

13 through page 20, recommends several reductions to the

14 Company's proposed level of hydro relicensing recovery.

15 Would you please comment on his recommendations?

16 A Mr. LaBolle, a Company witness, is

17 sponsoring rebuttal testimony that addresses in detail

18 the differences the Staff has with the Company's proposal

19 on hydro relicensing costs and introduces a revised level

20 of hydro relicensing recovery based upon the final

21 agreement. What I am proposing is the introduction of a

22 balancing account to capture the timing differences that

23 all parties to the Clark Fork Settlement Agreement

24 ("Settlement") agree will occur between when expenditures

25 are scheduled to occur and their actual disbursement

640

Falkner, Di-Reb 6
Avista

1 during the administration of the Settlement.

2 Mr. Lobb quotes from my original direct testimony,

3 first on page 19 of his direct testimony starting on line

4 12 and then again on the same page starting on line 17.

5 Basically, what is being noted is that the Settlement is

6 a "flexible" contract versus the notion of a very

7 prescriptive legal agreements otherwise common in power

8 supply contracting, etc. This flexibility was

9 intentional and is important to the Company in regards to

10 the continued

11

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Falkner, Di-Reb 6A
Avista

1 operation of the Clark Fork Projects. However, I am

2 aware that this flexibility while important for

3 administration Settlement, and in turn the operation of

4 the dams, has led to Staff concerns about incorrect

5 recovery levels. It was for these very reasons that in

6 my direct testimony, I only recommended that we pro form

7 in the O&M expense levels contained in the Settlement and

8 did not request rate recovery of amounts that had been

9 determined to be first year capital expenditures.

10 Q What do you propose to address Staff

11 concerns regarding the potential mismatch between

12 recovery and expense associated with the O&M level of

13 Settlement cost authorized in this case?

14 A As I noted earlier, I am proposing that a

15 balancing account be utilized to capture the differences

16 between the O&M level of Settlement costs ultimately

17 allowed in rates and the amounts that get expended on an

18 annual basis. FERC Account 253, Other Deferred Debits,

19 would accumulate a running balance that would represent

20 either a regulatory asset or a regulatory liability.

21 Credit entries to the account would be made for the

22 amount of O&M that is being recovered in current rates.

23 Debit entries would be made to the account for actual O&M

24 expenditures made pursuant to administration of the

25 Settlement. The Company proposes that any balance in the

642

Falkner, Di-Reb 7
Avista

1 Hydro Relicensing deferred balancing account be

2 consolidated with any balance in the current Idaho Power

3 Cost Adjustment ("PCA") deferral account, and would be

4 subject to refund or surcharge based upon the currently

5 authorized $2.2 million PCA trigger mechanism. Schedule

6 DMF-3 of Exhibit 24 uses a simple example to show

7 proposed entries for the balancing mechanism.

8 Q Does this balancing account "guarantee" the

9 Company recovery of the O&M level of the Settlement?

10

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14

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16

17

18

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20

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22

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643

Falkner, Di-Reb 7A
Avista

1 A No. In regards to the Credit entries for

2 the expense recognition that I mentioned earlier, I am

3 recommending that they be recorded at the actual level

4 authorized in this proceeding. The Company's case is

5 predicated upon a normalized test year level of customer

6 sales. With the Credit, or liability, entries to the

7 account being made based upon the authorized recovery

8 level, the Company will be at risk for the variability

9 between actual sales and the normalized test year.

10 Q What are you proposing in regards to

11 Settlement expenditures that are capital in nature?

12 A As I mentioned earlier, capital

13 expenditures associated with the Settlement are not a

14 component of this filing. Future capital expenditures

15 would be handled as normal plant-in-service additions and

16 would not technically be included in customer rates until

17 some future general rate proceeding includes them.

18 Q Is the Company proposing a different level

19 of expense and rate base for its Hydro Relicensing

20 adjustment?

21 A Yes. Based upon Mr. LaBolle's updated

22 analysis of the Settlement, the Company's proposed O&M

23 expense and rate base levels for this filing are lower.

24 The revised adjustment's effect on State of Idaho net

25 operating income is a decrease of $458,000. The rate

644

Falkner, Di-Reb 8
Avista

1 base amount is unchanged. The revised reduction to net

2 operating impact is lower than the original adjustment by

3 $33,000. In other words, pro forma net operating was

4 increased. Please refer to my Exhibit 24, Schedule

5 DMF-1, page 7 where this amount is shown in column PF14.

6 Q Potlatch witness, Mr. Peseau, suggests on

7 page 25, lines 9 through 16, of his direct testimony,

8 that "current" customers should not have to pay "for

9 something they may

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16

17

18

19

20

21

22

23

24

25

645

Falkner, Di-Reb 8A
Avista

1 never benefit from." He goes on to say, "There are no

2 assurances that a present ratepayer will still be a

3 customer after 2001 when the benefits of this low cost

4 hydro are distributed." Can you comment on those

5 assertions?

6 A Certainly. As noted in the rebuttal

7 testimony of Mr. LaBolle, the management decision to sign

8 and implement the Settlement agreement in 1999 was

9 integral to gaining acceptance by the numerous parties to

10 the Settlement. The Settlement was not entered into for

11 the FERC licensing process alone. It was entered into by

12 the Company to allow for maximum operational flexibility

13 of the Clark Fork Projects and to provide a level of

14 licensing and on-going operational costs lower than what

15 other electric utilities have experienced in long-term,

16 contested licensing proceedings. Whether a current

17 customer will still be a customer one year, two years or

18 three years from now is irrelevant. The decision to

19 enter into the Settlement was an operational decision

20 associated with management of those projects. If they

21 are current customers, they are obtaining energy from the

22 Clark Fork Projects. If they continue to be customers,

23 they will continue to benefit from the lower operating

24 costs that the Settlement is intended to produce. In the

25 final analysis, this is not unlike any investment or

646

Falkner, Di-Reb 9
Avista

1 expense associated with an asset (e.g. a distribution

2 pole, conductor, or a generating plant) where the useful

3 life will extend many years into the future.

4 Q Does Mr. Peseau argue that the Settlement

5 was an imprudent management decision?

6 A No. On Page 25, line 8 of his direct

7 testimony, Mr. Peseau states, "The issue I raise now is

8 not one of prudency." (emphasis added)

9 Q On Page 25 of Mr. Peseau's direct

10 testimony, starting on line 17 and

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Falkner, Di-Reb 9A
Avista

1 continuing through line 22, he suggests that an

2 equivalent of construction work in progress is being put

3 into rate base. Do you agree with this claim?

4 A No. I assume that, when he is talking

5 about rate base treatment, he is talking about the

6 deferred costs associated with the Settlement. The

7 Company did defer costs during the multi-year

8 negotiations associated with the creation of the

9 Settlement. The rationale for the deferrals was that

10 process was going to produce long-term, operational

11 benefits, not merely a new license, and would more

12 appropriately be reflected in a future period. The

13 process produced an operational agreement for the Clark

14 Fork Projects that has been signed and already

15 implemented. As I noted above, early implementation of

16 the Settlement was integral to acceptance by the parties.

17 The FERC licensing will, by necessity go on, but the

18 Settlement is in effect currently, it is not a "work in

19 progress."

20 IV - INJURIES AND DAMAGES

21 Q Are there proposed adjustments to the

22 Company's filed Injuries and Damages Accrual level?

23 A Yes. Staff witness Ms. Stockton and

24 Potlatch witness Mr. Peseau both raise issues with

25 including expenditures related to an ice storm in the 6

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Falkner, Di-Reb 10
Avista

1 year average used by the Company to produce a more

2 levelized accrual for expense recognition of uninsured

3 expenditures associated with operating a wide spread

4 distribution system. Ms. Stockton, on page 12, line 20

5 and 21, states that, "The Ice Storm" of 1996 "was an

6 extraordinary, non-recurring item, and does not reflect

7 on-going expenses." Further on page 13, on lines 15 and

8 16, she adds, "It is appropriate to remove expenses that

9 are non-recurring in nature." Mr. Peseau, starting on

10 page 26 and continuing on through the end of page 27,

11 attempts to introduce a concern of retroactive ratemaking

12 (page 16, line 15) and takes issue with use of

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20

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22

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Falkner, Di-Reb 10A
Avista

1 a 6 year average (page 27, lines 3 and 4).

2 Q Do you agree with these positions?

3 A No. The entire Injuries and Damages

4 accrual is a mechanism that takes utility expenditures

5 that are uneven and individual in nature and utilizes a

6 6-year average to produce a reasonable proxy for those

7 costs. In regards to the use of a 6-year average, it has

8 been a component of the Company's results of operations

9 for years and goes back to a previous general rate filing

10 in Washington. While Mr. Peseau is correct that

11 retroactive ratemaking is forbidden by law, it clearly

12 does not apply to this situation. The use of a multiple

13 year average or even simple amortization over a period of

14 time is very standard in ratemaking. In fact, in this

15 case the Staff has proposed that tree trimming costs be

16 based upon a 5-year average. Starting on page 14 of

17 Ms. Stockton's direct testimony and continuing through

18 line 2 on page 15, she states, "The 1997 total tree

19 trimming costs were the highest of the total costs

20 supplied for all five years. This adjustment removes the

21 variance from the five-year average from the test year."

22 Q Are you suggesting that the ice storm costs

23 are standard injuries and damages expenditures expected

24 to occur every 6 years?

25 A No. However, they are uninsured property

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Falkner, Di-Reb 11
Avista

1 losses that did occur in the 6-year time period that is

2 used for the rolling average of injuries and damage.

3 Additionally, storm damages of this level are not

4 unprecedented and it cannot be guaranteed that they will

5 not reoccur.

6 Q Are you aware of any other utility that is

7 allowed recovery of storm damages such as these?

8 A Yes. In 1993, the Washington Utilities and

9 Transportation, through the

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Falkner, Di-Reb 11A
Avista

1 Eleventh Supplemental Order in Docket Nos. UE-920433 and

2 UE920499, adopted for Puget Sound Power & Light, now

3 Puget Sound Energy, the following Washington Commission

4 Staff recommendation,

5 "Mr. Schooley proposed normalizing the storm
damage expense based on a six-year period, and
6 that truly extraordinary events be deferred as
extraordinary property damage and amortized into
7 rates over a six-year period. Commission Staff
also noted that the company in previous general
8 rate cases has in fact been regulated on a
normalized basis rather than on a deferral method
9 as suggested by the company. Mr. Schooley
proposed to define "catastrophic event" as one
10 affecting 25% or more Puget customers, occurring
infrequently, and affecting a wide geographic
11 area.

12 Q On page 16, lines 7 through 13, Ms.

13 Stockton states, "It has been over a decade since the

14 last (Avista) Idaho electric rate case, and if the next

15 rate case is not filed for another decade, then there

16 will be at least six years of over collection of the

17 amortization of the injuries and damages expense due to

18 the ice storm if the amortized amount is built into

19 rates." Do you agree with this statement?

20 A No. Utility customer rates are made up of

21 hundreds of different cost and return components.

22 Individual items are discussed during the course of a

23 general filing, but after rates have been set, utility

24 earnings are monitored based upon overall rates of

25 return. The Company currently files semi-annual

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Falkner, Di-Reb 12
Avista

1 normalized results of operations with the Staff. These

2 reports allow the Staff to monitor the Company's earnings

3 twice a year and provide the basis for Staff audits in

4 between general cases. If either the earnings reports or

5 an interim Staff audit indicates that the Company is

6 regularly overearning, the Commission can direct the

7 Company to file an updated case or the Staff can make a

8 filing on its own initiative.

9 Q Should the Injuries and Damages adjustment

10 be corrected for the allocation

11

12 /

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17

18

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24

25

653

Falkner, Di-Reb 12A
Avista

1 issue noted by Ms. Stockton on page 11, starting on line

2 15 of her testimony?

3 A Yes it should.

4 V. - DSM INTEREST ADJUSTMENT

5 Q In revised testimony filed on May 12, 1999,

6 IPUC Staff Witness Mr. Lynn Anderson proposes an interest

7 adjustment of approximately $240,000. What is the

8 Company's response?

9 A The Company agrees that some level of

10 interest should be credited to Schedule 91 (Energy

11 Efficiency Tariff Rider) revenues. Before I respond to

12 Mr. Anderson's proposed adjustment, I want to briefly

13 explain the Company's perspective on this issue.

14 The Company has always planned to maintain a

15 surplus of funds for several reasons. Many DSM projects

16 in the commercial and industrial sectors require over a

17 year to build out and, ultimately fund. Thus, the

18 Company must commit funds which has the effect of taking

19 them out of the available pool while retaining the funds

20 on the books of the Company.

21 Q Turning to Mr. Anderson's proposed

22 adjustment, have you had an opportunity to review his

23 proposal?

24 A Yes Exhibit 24, page 1 of Schedule DMF-2

25 recreates Mr. Anderson's spreadsheet. Adjusting for

654

Falkner, Di-Reb 13
Avista

1 average annual balances, rather than end-of-year balance,

2 and factoring in the one-month lag as found in the

3 original agreement reduces the interest adjustment by

4 $54,789.

5 The Company, over the course of the Energy

6 Efficiency Tariff Rider period of 1995 to current, has

7 not charged corporate service expense to the energy

8 efficiency programs.

9

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20

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22

23

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655

Falkner, Di-Reb 13A
Avista

1 These services include basic corporate overhead such as

2 floor space, telephone usage, and the like. The Company

3 would offset any interest adjustment with such expenses

4 as well as programmatic lease investments (which are

5 included in column d on pages 2 and 3 of Schedule DMF-2).

6 This offset, at a 10% interest rate, would result in an

7 interest adjustment of $124,565 as shown on Page 2 of

8 Schedule DMF-2.

9 Q Do you have concerns about the 10% interest

10 level as originally specified?

11 A Yes. Interest on Idaho customer deposits

12 accrues at a rate of 6%. This is a more reasonable level

13 and better reflects the rate at which short-term revenue

14 can earn interest. The Company proposes that the current

15 deposit interest rate be used to calculate interest on

16 DSM balances. A six percent rate, which is the

17 Commission-approved interest rate for customer deposits

18 over the life of tariff rider through 1998, would provide

19 an interest adjustment total of $71,422 as shown on page

20 3 of Schedule DMF-2. Irrespective of the interest

21 adjustment which stems from this case, the Company

22 requests that future interest on DSM balances be

23 calculated based on the Commission-approved interest rate

24 for customer deposits.

25 VI. - MISCELLANEOUS GENERAL EXPENSES

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Falkner, Di-Reb 14
Avista

1 Q Staff proposes an adjustment to test year

2 expenses recorded in FERC Account 930, Miscellaneous

3 General Expenses. On page 16, starting on line 16,

4 Ms. Stockton states, "Staff removes 20% of this account

5 at the Idaho jurisdictional level to remove expenses that

6 are not beneficial to customers and reflect them as a

7 below-the-line expense." One assertion of the Staff in

8 support of this adjustment is that "they do not provide a

9 direct benefit to the customer." Another is that, "These

10 type of activities are similar to lobbying activities, in

11 that it `gets the name out there'. Expenses associated

12 with

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25

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Falkner, Di-Reb 14A
Avista

1 lobbying activities are below-the line activities." Do

2 you agree with the Staff adjustment and the Staff

3 characterization of these costs?

4 A No. The primary problem with this

5 adjustment is that the 20% reduction is an unsupported

6 percentage. Secondarily, by FERC definition, "This

7 account (930.20) shall include the cost of labor and

8 expenses incurred in connection with the general

9 management of the utility not provided for elsewhere."

10 (emphasis added) "General" management costs will often

11 not provide "a direct benefit to the customer." However,

12 they can be just as essential to the operations of a

13 major utility as, for example, supervisor of hydro

14 operations. This fact was recognized by the FERC

15 accounting regulations through the inclusion of these

16 defined costs in an above-the-line operating account.

17 Q Does the Company include lobbying costs in

18 account 930?

19 A No. The Company does not charge lobbying

20 costs to account 930. Those costs are generally charged

21 to non-operating accounts and are already excluded from

22 the revenue requirement.

23 Q Is the Company active in the communities in

24 which it serves?

25 A Yes. As a matter of fact, the Company

658

Falkner, Di-Reb 15
Avista

1 takes very seriously its responsibility as a corporation

2 that is providing an essential service to the communities

3 in which it serves. Area Coordinators, or AC's, who do

4 charge account 930, to some degree are extension of

5 executive management, and do interact with business

6 organizations. These AC's also are responsible for

7 dealing with the local and federal officials, who also

8 belong to local business organizations, and, for example,

9 are responsible for approving local development policies

10 and franchise agreements that ultimately impact the

11 Company's cost of operating in their respective

12 communities.

13

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Falkner, Di-Reb 15A
Avista

1 Q Does the Staff take issue with costs such

2 as stockholder meetings, director fees and publishing

3 annual reports that are charged to account 930?

4 A No, they do not. However, "shareholder

5 value" is mentioned on page 17, line 6, and a 20% across

6 the board reduction in account 930 charges technically

7 disallows portions of those costs. It should be noted

8 that common equity capital is just as essential to the

9 Company's operations as debt financing. Just as debt

10 financing has associated costs, so does equity financing.

11 The ultimate goal for the Company, and in turn the

12 customer, is efficient access to capital markets. It

13 would be inappropriate to disallow portions of costs

14 related to maintenance and management of the Company's

15 common equity component.

16 VII. - OTHER STAFF ADJUSTMENTS

17 Q What is the Companies position in regards

18 to the Staff's adjustments to Tree Trimming costs, Total

19 Income Tax and the associated modification to the

20 Conversion factor?

21 A The Company is not contesting those

22 adjustments.

23 VIII. - SUMMARY

24 Q What is the Company's revised requirement

25 after taking into account Staff adjustments that have

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Falkner, Di-Reb 16
Avista

1 been accepted and Company revisions to the originally

2 filed adjustments?

3 A After taking into account the accepted

4 Staff adjustments, adjustment revisions and corrections

5 outlined in both my testimony and Staff testimony, the

6 Company's revised requirement is $13,456,000 is detailed

7 in Schedule DMF-1 which is part of my Exhibit 24.

8 Q Could you briefly describe Schedule DMF-1

9 of your Exhibit 24?

10

11 /

12

13 /

14

15 /

16

17

18

19

20

21

22

23

24

25

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Falkner, Di-Reb 16A
Avista

1 A Yes. Page 1 of Schedule DMF-1 shows the

2 derivation of the revised requirement by working from the

3 Company's original revenue requirement, implements the

4 accepted Staff adjustments and proposed Company revisions

5 and then applies the Staff's recommended Conversion

6 factor to arrive at the Company's revised requirement.

7 Q What do the remaining pages, 2 through 7,

8 represent?

9 A Pages 2 through 7 is actually my original

10 Exhibit No. 11 which is a columnar listing of all Company

11 adjustments with columns PF10 through PF15 added to show

12 the proposed changes to the Company's original revenue

13 requirement. Column PF 10 is Staff Depreciation

14 adjustment. Column PF11 is Staff Tree Trimming

15 adjustment. Column PF12 is Staff Total Income Tax

16 adjustment. Column PF13 is the correction of the

17 original Injuries and Damages adjustment. The Company

18 and Staff still disagree on inclusion of Ice Storm costs

19 in this adjustment. Accordingly, the Company adjustment

20 still includes those costs. Column PF14 is the Company's

21 Hydro Relicensing Revision. Column PF15 is the Company's

22 Debit Interest revision to take into account Column

23 PF10's impact on rate base.

24 Q Does that conclude your direct testimony?

25 A Yes, it does.

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Avista

1 (The following proceedings were had in

2 open hearing.)

3 MR. MEYER: Mr. Falkner is available for

4 cross.

5 COMMISSIONER SMITH: Mr. Ward, would you

6 like to ask Mr. Falkner some questions?

7

8 CROSS-EXAMINATION

9

10 BY MR. WARD:

11 Q Mr. Falkner, my first few questions have to

12 do with your direct testimony. If you'd turn to page 5,

13 lines 3 through 8.

14 A I'm there.

15 Q At this juncture, you're answering a

16 question about the causes of the need for the rate

17 increase or the revenue deficiency and I'm not going to

18 go through the list, but would it be fair to say that

19 most of those reasons cited there or causes are things

20 that grew over time with some exceptions, they didn't

21 just suddenly happen in 1997?

22 A That would be true.

23 Q Now, I want to have you flip back to page 4

24 of that direct testimony and on this page at the top of

25 the page you're discussing the chart that appears on the

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Wilder, Idaho 83676 Avista

1 bottom of the page of page 4 and you explain that it's on

2 a Commission basis and fully normalized; is that correct?

3 A I'm saying that it is on a Commission basis

4 arrangement, that it's historically accepted by this

5 Commission, yes.

6 Q And it includes normalized weather and

7 similar items?

8 A Yes, we provide the report semiannually to

9 the Commission for periodic review.

10 Q Now, do you recall what overall rate of

11 return the Company is requesting in this case?

12 A Yes, 9.446.

13 Q And you're probably less likely to have on

14 the tip of your tongue the Staff's recommendation.

15 A I think it translated to 9.07.

16 Q Okay, thank you, you passed both. Now, as

17 I look at this chart, there are a couple of things that I

18 notice right away. First of all, I calculated the

19 average return for the seven years prior to 1997 and

20 would you accept, subject to check, that that's roughly

21 9.89 percent as an average of those seven years?

22 A Subject to check, yes.

23 Q And in the two years prior to the test

24 year, you met or exceeded, did you not, the rate of

25 return that you're requesting in this case?

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Wilder, Idaho 83676 Avista

1 A Yes.

2 Q And in all seven years you met or exceeded

3 the rate of return the Staff is recommending in this case

4 prior to 1997?

5 A That would be correct.

6 Q And then we get to 1997 and the rate of

7 return drops 155 basis points. The first thing, is there

8 any other variation of this magnitude on this chart?

9 A Not on this chart, no.

10 Q And can you explain why the test year

11 results present such nominal results in this chart?

12 A No detailed analysis was actually done to

13 track the changes year to year, but a quick look when it

14 was originally put together showed there were increases

15 in power supply costs, production costs and A&G costs

16 were the most noticeable components. I should also point

17 out this is a rate of return and the rate base in Idaho

18 is approximately 360 million and it's a little more

19 sensitive to changes in the net operating income than,

20 say, our Washington jurisdiction which would be twice as

21 large.

22 Q All right. I'm not sure any of those

23 reasons really explain why that drop, why a drop of that

24 magnitude occurred. Did you attempt to quantify the

25 effect of those various changes on that rate of return?

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Wilder, Idaho 83676 Avista

1 A No, no, I did not. I did ask if there were

2 any major power supply changes and there was an

3 indication that a contract had fallen out between the two

4 years, one of the higher margin contracts we had that was

5 a long-term arrangement that terminated. Outside of

6 that, I didn't get the detail.

7 Q Would you agree with me that the test year,

8 that a test year is a baseline of sorts on which we're

9 going to build a revenue requirement?

10 A Right, we're using a historical test year

11 as a proxy for a revenue requirement going forward, yes.

12 Q Do you think a reasonable person looking at

13 this chart would have some misgivings about accepting

14 1997 as a baseline in this case?

15 A A reasonable person? A reasonable person

16 could question why there's a difference, but the numbers

17 are based on actuals for the period. They've been put

18 under audit by external auditors, by Deloitte and

19 Touche. They've gone through the scrutiny of our

20 internal accounting department and they've also gone

21 through the review of the Commission Staff in detail.

22 Q Okay. Let's turn to your rebuttal

23 testimony, if you would. I want to start on page 2,

24 lines 20 through 21.

25 A I'm there.

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Wilder, Idaho 83676 Avista

1 Q Okay, at that point you're correcting

2 Dr. Peseau's phrase change in accounting to a change in

3 accounting estimate and I would agree that correction is

4 appropriate, but I want to ask you about the assertions

5 on lines 10 and 11 where you state that in a somewhat

6 unusual way and I just want to make sure we're clear,

7 does an increase in depreciation rates standing alone

8 always increase cash flow?

9 A If there's an associated change in revenue,

10 yes.

11 Q All right. Let me think about that for a

12 minute. Actually, it's if there's no change in revenue,

13 isn't it?

14 A No. If we change our depreciation rates

15 right now absent any change in revenues, our cash flows

16 remain the same.

17 Q You're right, okay. All right, but

18 assuming the Commission accepts your proposed revision to

19 depreciation rates, it will in fact increase your cash

20 flow?

21 A Yes, it would, as would any change in our

22 revenue requirement at this point in time.

23 Q Now, I want to follow on over to page 3,

24 line 2 and 8, and you have to start with the first line

25 of the question on the bottom of page 2 and that question

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Wilder, Idaho 83676 Avista

1 is, "If the depreciation expense revisions are approved

2 by this Commission, will shareholder profits increase?"

3 And you say, "Absolutely not," and then you

4 go on to explain why. Now, perhaps the best way to get

5 at this is to suggest that perhaps you've missed a

6 crucial distinction in Dr. Peseau's choice of words. If

7 Dr. Peseau had said that depreciation rate increases

8 increase earnings, everything you say there we would

9 happily concede; that is, from lines 2 to 8 would be

10 correct, but he didn't say increase in earnings, he said

11 increase shareholder profits, so let me walk through with

12 you just a bit what that distinction means.

13 Is an increase in cash flow invariably

14 regarded as a positive development for a company by

15 market analysts?

16 A I would have to say yes.

17 Q And that's because it has some advantages

18 to the company; for instance, to just pick some, it

19 facilitates reinvestment; correct?

20 A Yes.

21 Q It can lower borrowing costs, it can

22 increase some measures of interest coverage and dividend

23 coverage; would those be true?

24 A There's numerous uses for cash flow and how

25 it impacts investors I would actually prefer to defer to

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Wilder, Idaho 83676 Avista

1 Mr. Avera.

2 Q Well --

3 A But I do understand, yes, there are a

4 number of utilizations for increased cash flow.

5 Q I'm not going to take you too far into the

6 technicalities of this.

7 A Okay.

8 Q It can even be used to buy back stock which

9 is a project that Avista has in mind, can it not?

10 A Yes, it can.

11 Q And do all those things, all other things

12 being equal, tend to increase stock prices?

13 A Some of them can.

14 Q And if I'm, as I am, an Avista shareholder

15 and the stock goes up, do I have a profit or a potential

16 profit?

17 A I guess I would agree that there is a

18 shareholder profit. The original reading of profit in my

19 mind was earnings which was net income, so if we're

20 looking for more of a refined definition, I agree.

21 Q Okay. Well, as I say, that's certainly

22 understandable. Let's go on to page 4, lines 8 through

23 10. Here you say if one accepts the contention that the

24 net book value of utility assets understates their market

25 value, shouldn't then utility rate base for these same

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CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 assets be increased, and you go on. Would it also be

2 true that if you did that, that is, increase the rate

3 base to -- well, first of all, are you aware that that's

4 a very old source or bone of contention in ratemaking

5 that died out 70 years ago or so?

6 A No, I'm not.

7 Q The flip side of that is if we in fact

8 increased, discarded original cost ratemaking and moved

9 to market value ratemaking, would the flip side be that

10 shareholders would forfeit any right to any gains on the

11 sale of assets?

12 A I don't know.

13 Q You go on to dispute any linkage between

14 market value of assets and depreciation rates and I think

15 we'll all be best served if I don't go through that by

16 nits and gnats, but I do want to have you look at an

17 exhibit briefly.

18 MR. WARD: May I approach the witness?

19 COMMISSIONER SMITH: Certainly.

20 (Mr. Ward approached the witness.)

21 MR. WARD: I believe our next exhibit

22 number is 211, Madam Chair.

23 COMMISSIONER SMITH: Yes, it is.

24 MR. WARD: I'd like this to be marked as

25 Exhibit 211 for identification.

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Wilder, Idaho 83676 Avista

1 COMMISSIONER SMITH: We will mark this as

2 Exhibit 211.

3 (Potlatch Corporation Exhibit No. 211

4 was marked for identification.)

5 Q BY MR. WARD: Mr. Falkner, I've handed a

6 you a two-page exhibit identified as Exhibit No. 211.

7 Let me ask you if you recognize that.

8 A This is an excerpt from the depreciation

9 study that was performed by the consultant Deloitte and

10 Touche.

11 Q And that study forms the basis for or the

12 underpinnings for your request for increased depreciation

13 rates; is that not correct?

14 A Yes, it does.

15 Q Now, one of the things that struck me in

16 looking at this exhibit is in general terms -- well,

17 let's focus on transmission plant because it's easier to

18 just pick one category. Would it be fair to say that

19 while there are some adjustments to lives and some

20 adjustments to Iowa curves, the fact is that in the

21 transmission plant category, the big increase or the bulk

22 of the increase in the depreciation rate is accounted for

23 by an increase in net salvage; do you see that?

24 A I do.

25 Q Now, first of all, let me ask you, in the

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CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 real world, how realistic is it to assume that

2 transmission facilities as valuable as they are today

3 will have a net salvage cost approaching in some cases

4 30, 40, 45 percent cost?

5 A I really can't answer that. The net

6 salvage number is actually salvage less cost of removal,

7 so one of the bigger components could be the additional

8 cost of removal. I'd like to point out that I really am

9 not a statistical expert on the depreciation study

10 itself. I do know that they went through our actual

11 historical retirements and the cost of removal prior to

12 this calculation.

13 Q Well, fine, I'll accept that, Mr. Falkner,

14 but let me just explore that with you just a bit. As you

15 say, the net salvage is driven in large part by cost of

16 removal. Knowing what you know about general

17 circumstances of the utility industry in this part of the

18 country, at least, how likely is it in the foreseeable

19 future that we will ever see transmission capacity

20 removed?

21 A I can't answer that. I'm not aware of any

22 transmission that has been --

23 Q Would you at least agree with me that it's

24 somewhat like Twain's observation about land, they ain't

25 making any more of it; isn't that true in this industry?

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Wilder, Idaho 83676 Avista

1 A We're not making any more land, that's

2 true.

3 Q And we're making precious little headway in

4 increases in transmission capacity; isn't that true?

5 A I honestly don't keep up with that.

6 Q Let me, given this is not your field, I

7 won't ask you more than one question about it, but if

8 you'd turn over to the second page, this line is not

9 numbered, but under 316, there's an entry for Centralia,

10 Colstrip and Kettle Falls and under the Centralia entry,

11 I see terminal net salvage at 25.9. Do you see that?

12 A Yes, I do.

13 Q Do you understand that to be a percentage

14 of the cost?

15 A I would assume that's what it is.

16 Q If you know.

17 A I do not know.

18 Q Back to page 9 of your testimony, rebuttal

19 testimony, I'm sorry.

20 A I'm there.

21 Q All right. On lines 13 through 14, here

22 we're talking about the dispute about what is to be done

23 about O&M costs related to relicensing that are presently

24 being paid, as I understand it; is that your

25 understanding?

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CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 A That's my understanding. The settlement

2 agreement was implemented in early 1999.

3 Q Okay, and I take it we don't have a similar

4 dispute about capital costs and one-time costs of

5 relicensing, that those are being, in my words and I may

6 not be using the proper accounting term, capitalized and

7 held for implementation in 2001?

8 A No, that's not correct. In this case,

9 we're asking for the O&M component of incremental costs

10 associated with the implementation of the settlement

11 agreement. Any capital -- any costs of the settlement

12 agreement that are determined to be capital will just go

13 through our normal capitalization process, would be put

14 in plant in service and could become part of a future

15 rate base. It's not tied to implementation or FERC

16 licensing. It's not tied to 2001 exactly.

17 Q All right, but at any rate, it's not an

18 issue in this case?

19 A Correct, we're not asking for recovery in

20 this case.

21 Q Now, the question here is one of not

22 whether Avista is entitled to recover for its O&M costs

23 that it's currently paying, but who pays and when; is

24 that your understanding as well?

25 A I think that's the point that Mr. Peseau

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CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 was making, yes.

2 Q And you say in trying to analyze who

3 benefits from that, you say, "If they are current

4 customers, they are obtaining energy from the Clark Fork

5 projects," that's clearly true. "If they continue to be

6 customers, they will continue to benefit from the lower

7 operating costs that the settlement is intended to

8 produce," and I'm willing to accept that as true, but let

9 me ask you about the person who falls in between there;

10 that is, assume that I am an existing customer of Avista,

11 but I either don't plan to be or won't be in 2001 when

12 the license reissues. Do you have that in mind?

13 A I do.

14 Q Now, if I'm a purely selfish person and

15 looking out only for my own economic interests, wouldn't

16 my contention be that A, I'm already paying for the

17 original license in my rates and B, frankly, I don't care

18 whether you relicense or not because I'm not going to be

19 a customer, quite a selfish argument, but it could be

20 made, could it not?

21 A It would be a selfish argument, but it

22 could be made.

23 Q But isn't it true that in fact in

24 ratemaking we honor and accept that selfish argument by

25 ensuring that we have intergenerational equity as a

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Wilder, Idaho 83676 Avista

1 principle of ratemaking?

2 A You'd have to accept that the argument is

3 valid before you bring up intergenerational inequities.

4 In this case, the settlement agreement was entered into

5 to provide flexibility currently for operation of the

6 dams. It also will facilitate ultimate approval in the

7 FERC process, but it has been implemented now and they

8 are currently receiving benefits associated with the

9 operation and ongoing operations of the Clark Fork

10 projects.

11 Q Okay. Mr. Falkner, I deliberately stated

12 it the first time in an overstated way. Now, let me make

13 the same statement in a more neutral way. Isn't it true

14 that in ratemaking we invariably assign costs no matter

15 when occurred or paid only to those who benefit or cause

16 the costs to be incurred to the extent we can?

17 A I think that's the goal, yes.

18 Q And in fact, let me read you a short

19 excerpt from your direct testimony, if you'd go back to

20 it just a moment. On page 26, lines 4 through 8, if

21 you'd look at that testimony.

22 A Yes.

23 Q Here you say, "Matching is an element of

24 regulatory philosophy that addresses intergenerational

25 equity. Intergenerational equity means costs are borne

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CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 by the generation of customers that caused them to be

2 incurred, not by a later generation," and then you go on

3 to say that this ensures that charges to customers

4 reflect the actual costs of providing service.

5 Now, for a customer sitting here today,

6 that customer as of today that will not be there in 2001

7 when relicensing occurs, that customer is not benefiting

8 from or causing that relicensing in any way, is he?

9 A The relicensing specifically, no, but the

10 ongoing operations of the dam, yes, and I probably should

11 defer any more detail to Mr. LaBolle who is going to be

12 getting into the detail behind the settlement itself.

13 It's my understanding there are costs included in the

14 settlement that we would have been incurring otherwise

15 outside of the licensing process, and also in my reading

16 on it, I tried to pick up a little bit on the

17 depreciation. Intergenerational equity is a goal that

18 the Commission weighs in their ultimate determination of

19 the appropriate revenue requirement.

20 Q But isn't it your understanding,

21 Mr. Falkner, that what's in dispute here is not any

22 ongoing O&M on the projects, but rather the incremental

23 O&M associated with the relicensing agreement?

24 A I think the dispute put by Mr., Dr. Peseau

25 is the timing of implementation of the costs, yes.

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1 MR. WARD: That's all I have. Thank you.

2 COMMISSIONER SMITH: Thank you, Mr. Ward.

3 Mr. Shurtliff.

4

5 CROSS-EXAMINATION

6

7 BY MR. SHURTLIFF:

8 Q Mr. Falkner, at page 2 of your rebuttal

9 testimony at lines 8 through 10, starting, I guess, at

10 line 6, you indicate that there's -- you take exception

11 to the proposition that there's a change of accounting

12 being suggested in the case and you state the Company is

13 simply revising its estimate of the apportionment of some

14 of its long-lived assets based upon a detailed study

15 performed by a depreciation expert from an international

16 professional accounting firm, so I take it that from that

17 that the -- if you're following generally accepted

18 accounting practices, you've just increased the velocity

19 of depreciation; is that what you're saying?

20 A We revised the estimate based on updated

21 information.

22 Q Can you tell me and the Commission how much

23 of the $13,456,000 increase in revenue requirement

24 requested by the Company is attributable to simply

25 revising the estimate of the apportionment of some of its

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1 long-lived assets?

2 A The original proposal, estimate, the

3 original change in accounting proposed in the case was

4 approximately 2.4 million. It's been revised downward

5 based on Staff review, the Company has accepted, to

6 1.7 million, approximately.

7 Q So the answer to my question is that the

8 change, the revision accounts for 1.7 million of the

9 requested amount?

10 A Yes.

11 Q The previous use of the unrevised

12 methodology, were they wrong, then?

13 A No, they were best estimates available at

14 the time.

15 Q And so I take it implicit in that answer is

16 the suggestion that this new revision is the best method

17 available now?

18 A Yes, it is.

19 Q Could someone disagree with that

20 proposition?

21 A Yes, they can and Staff did as a matter of

22 fact.

23 Q And someone could even disagree further and

24 suggest that no revision is necessary?

25 A If there was a study performed that went to

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CSB REPORTING FALKNER (X)
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1 the same level of detail that Deloitte performed and they

2 could compare the assumptions, you could make the

3 argument.

4 Q Well, indeed, you could make the argument

5 if Deloitte hadn't made the study and proposed a

6 revision, couldn't you? We're basing it on the fact that

7 Deloitte did a study.

8 A We're basing it on the fact that there was

9 a detailed historical review of updated information, yes.

10 Q You didn't hire Deloitte to do a study to

11 see if you should decrease the depreciation rate, did

12 you?

13 A Actually, I wasn't involved in the hiring

14 of Deloitte, but Deloitte was hired with the express

15 purpose of updating our depreciation rates and as a

16 matter of fact, some rates did go down.

17 Q So rates went down and others went up?

18 A Correct.

19 Q And the net effect is $1.7 million

20 difference?

21 A In this case. Some of our gas properties

22 the depreciation expense went down, specifically our

23 Oregon jurisdiction. Overall, they went down.

24 Q Mr. Ward covered a number of areas and I

25 don't need to retrack those, so the only other area that

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1 I have some questions about, then, Mr. Falkner, would be

2 this ice storm thing and I don't think it's a big

3 matter. Do you recall talking about that?

4 A I do.

5 Q And did you -- in that regard, I take it

6 the ice storm was perceived to be an anomaly and created

7 a considerable difficulty for the Company and its

8 customers; is that correct?

9 A It was considered a difficulty, yes.

10 Q And that difficulty resulted in the

11 expenditure of money on the part of the Company, did it

12 not, to take care of the problems caused by the ice

13 storm?

14 A Yes, it did.

15 Q And it doesn't happen every year,

16 hopefully, it hadn't happened before to the same extent,

17 had it?

18 A Not on our system, no.

19 Q And to recapture, as I understand it, to

20 recapture those dollars, you're suggesting that it be

21 flowed in, and I oversimplify, on a six-year basis?

22 A We're proposing that it be included in the

23 injuries and damages accrual which uses a six-year

24 average of historical costs, yes.

25 Q Now, in that regard, and the Staff goes

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CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 into it in much greater length than I need to, but I read

2 your testimony, you're not suggesting there is going to

3 be an ice storm every six years of that same magnitude

4 but some other kind of like event, accident or

5 extraordinary expense.

6 A Correct. I'm not suggesting we'll see an

7 ice storm every six years. All I'm recognizing is the

8 fact that we did incur costs associated with an ice storm

9 in the period we're discussing and it was a non-insured

10 injury or damage.

11 Q How much was that damage in dollars?

12 A Roughly 15.7 million.

13 Q And the Idaho apportionment of that?

14 A I can't remember that off the top of my

15 head, but it would be -- it wasn't necessarily

16 apportioned, it was more directly assigned. I'd have to

17 look at that up.

18 Q And then we would further amortize that

19 over a six-year period?

20 A It would be built into the six-year

21 average, yes.

22 Q In that regard, did you happen in the

23 course of your preparation for this case review the Idaho

24 Power case wherein the Idaho Power Company sought some

25 what they considered to be extraordinary expenses in

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1 cleaning up a site at what's called the Pacific Hyde?

2 A No.

3 Q And you don't know how the Commission

4 treated that extraordinary expense in that rate case?

5 A I do not, but I do know during the course

6 of my review, I did note in my testimony, direct rebuttal

7 on page 12, that the Washington Commission evaluated

8 extraordinary storm damage for Puget Sound Energy and

9 they explicitly allowed deferral accounting and future

10 recovery of those costs along with a six-year average of

11 ice storm damage.

12 Q You're also aware that the Washington

13 Commission and the Idaho Commission do very many things

14 differently, aren't you?

15 A I'm aware there are differences, yes.

16 Q In the Idaho Power case with Pacific Hyde,

17 you don't know that the Commission suggested that the

18 Company should have simply either sought the relief at

19 that time or accrued it for future recovery?

20 A No, I'm not aware of that. In this case,

21 we happened to have an accounting mechanism that allowed

22 for a six-year average of historical, so there was no --

23 actually, the determination was not to get a specific

24 determination at that point in time.

25 MR. SHURTLIFF: I think I have no further

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CSB REPORTING FALKNER (X)
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1 questions. Thank you, Mr. Falkner.

2 COMMISSIONER SMITH: Thank you,

3 Mr. Shurtliff.

4 Mr. Woodbury.

5 MR. WOODBURY: Thank you, Madam Chair.

6

7 CROSS-EXAMINATION

8

9 BY MR. WOODBURY:

10 Q Good morning, Mr. Falkner.

11 A Good morning, Mr. Woodbury.

12 Q Looking at your direct testimony, you speak

13 of the Schedule 91 DSM tariff rider, page 14, and you

14 state that that's North America's first non-bypassable

15 distribution charge to fund energy efficiency and that's

16 not applicable to your special contract customers;

17 correct?

18 A To the best of my knowledge, no.

19 Q And you have one special contract customer

20 and that being Potlatch?

21 A Yes.

22 Q And that Potlatch contract expires when?

23 A End of 2000, 2001.

24 Q And would it be the Company's intention in

25 its negotiations with Potlatch to have this tariff rider

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Wilder, Idaho 83676 Avista

1 apply to that company?

2 A I can't answer that, at least I'm not aware

3 that that would be part of the policy.

4 Q So it would not be -- it's not Avista's

5 intent to have this non-bypassable distribution charge

6 apply to special contract customers?

7 MR. MEYER: Well, don't speculate.

8 THE WITNESS: I don't know.

9 Q BY MR. WOODBURY: The Company has not

10 considered that?

11 A I'm not involved in the Potlatch contract

12 renegotiation.

13 Q That's fine. On page 14 of your direct

14 testimony, you state that the Commission was to determine

15 the prudence of your DSM investments at the time of a

16 general rate case and in fact, you are asking that the

17 Commission issue a finding in this case that the energy

18 efficiency revenues collected under Schedule 91 have been

19 prudently expended and you would agree, would you not,

20 though, that not all the monies that have been collected

21 pursuant to your surcharge have been expended, that you

22 maintain a balance within the DSM account?

23 A Correct, there is currently a timing

24 difference between the expenditures and what has been

25 collected.

685

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 Q And your average balance maintained has

2 been what since the inception?

3 A For the Idaho share? My guess is between

4 3-$700,000.

5 Q Okay, and were you here yesterday when we

6 were discussing the -- well, essentially, in your

7 rebuttal testimony, you state that it's always been the

8 Company's plan to maintain a surplus of funds for several

9 reasons in the DSM account.

10 A Yes.

11 Q And yet, in the '94 application, the

12 Company stated that the DSM tariff rate would also be

13 adjusted up or down to match funding with the DSM program

14 costs and to keep the deferred balance as close to zero

15 as possible.

16 A I'm aware that that's how it read, yes.

17 Q And yesterday he indicated that essentially

18 about three-quarters of a million dollars is as close to

19 zero as the Company can come?

20 A I don't recall that.

21 Q The balance that you maintain is about

22 three-quarters of a million dollars in that account.

23 A From the information I've seen, that built

24 up since 1994 through 1998. The first year the balance

25 was negative and there were some timing differences with

686

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 BPA payments. It went up and it went down, but on

2 average, it maintained a positive balance and the

3 rationale for that is that some of the projects take a

4 long-term period to implement. There's a construction

5 phase, there's an analysis phase, but the funds are

6 technically committed, they just haven't been expended

7 from the balance, so the balance itself doesn't give a

8 true picture of how the expenditures are being utilized.

9 There's another accounting mechanism built

10 in that the Company utilizes on lease payments where the

11 cash has actually already been expended, but for

12 administrative purposes, the Company credits it back to

13 the balance and it shows a positive balance.

14 Q All right, and with the Company's

15 application for the DSM tariff surcharge, as part of that

16 application, you stated that interest should accrue on

17 the undistributed balances.

18 A Yes, that was part of the stipulation.

19 Q And that interest that the Company cited

20 there was 10 percent in that case.

21 A The parties agreed on 10 percent.

22 Q And in that particular case, was there to

23 be any offset to that interest accrual?

24 A An offset to that interest accrual?

25 Q Yes.

687

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 A Not explicitly, no. The interest rate was

2 to be charged against the DSM balance, any DSM balance,

3 that was there and the balance represents revenues

4 collected less prudently-incurred DSM expenditures.

5 Q On Exhibit 24, schedule DMF-2, page 2, the

6 fifth column --

7 A I'm not there yet.

8 MR. MEYER: Say that again, Scott.

9 MR. WOODBURY: Yeah, Exhibit 24,

10 schedule DMF-2, page 2, fifth column.

11 THE WITNESS: Page 2?

12 Q BY MR. WOODBURY: Yes.

13 A Yes.

14 Q You propose offsetting the accrual of DSM

15 interest by nearly $265,000 for what you call Idaho

16 Corporate Services above rate base?

17 A Yes. What that column represents is an

18 estimate of the basic overhead charges that the energy

19 services group receive from the infrastructure of the

20 Company, telephone usage, floor space, the like. These

21 are the sort of charges that the energy services group

22 would incur if we had moved them off site to be a

23 self-contained unit.

24 Q You didn't include these Idaho corporate

25 services in the DSM expenditures listed in your

688

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 Exhibit 12.

2 A No. No, this is basically the fact that

3 we're going back and recalculating interest. It was an

4 accounting correction and the proposal is that the

5 charges of these overheads, corporate overheads, also be

6 an accounting correction.

7 Q And, again, this offset was not proposed by

8 the Company in its tariff rider case?

9 A It's my understanding it was not explicitly

10 stated, no. The only thing that was going to be offset

11 against tariff riders were prudently-incurred DSM

12 expenditures in support of the DSM programs.

13 Q Turning to your rebuttal on page 14,

14 lines 7 through 15, am I correct in reading your answer

15 that you're proposing that 6 percent interest accrue to

16 DSM balances from 1994 through 1998 rather than the

17 10 percent that the Company proposed and the Commission

18 approved?

19 A What we're proposing, yes, what we're

20 proposing is that the short-term interest rate that the

21 Commission approves annually on customer deposits be

22 applied to the timing differences on the DSM balance

23 itself. 6 percent was the rate that was approved in

24 1998, in effect in 1998.

25 Q And looking at the utility customer

689

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 relations rules of the Commission, Rule 106 sets out the

2 historical interest rates that have been in effect since

3 the Commission approved interest on deposit amounts by

4 customers and those are the rates, you know, from 1994,

5 that was, like, 3 percent; in '95, 5 percent; and '96

6 forward it's been 6 percent until January 1 of this year

7 when it was 5, but are you indicating that when the

8 settlement was reached back in the tariff rider

9 implementation case that it was the intent of the parties

10 to link it to these interest rates, because back then it

11 was, what, 12 percent?

12 A I'm sorry, what was 12 percent?

13 Q Excuse me, this was approved in '94; is

14 that correct?

15 A Yes.

16 Q When it was 3 percent?

17 A Yes.

18 Q And what was approved by the parties and

19 the Commission was 10 percent back then, so please

20 explain the linkage.

21 A Well, to the best of my knowledge, there

22 was no detailed study or determination of the backup

23 behind the 10 percent and that it could have been

24 construed as a placeholder for a future determination.

25 Q And the Company never made any application

690

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 to change the 10 percent?

2 A The Company did not. The Company is

3 proposing, though, to going, at the very least going,

4 forward that the rates determined annually by the

5 Commission for customer deposits be applied to this and

6 that can be taken up with the triple E board, excuse me,

7 the external energy efficiency board, that will be having

8 a tariff filing shortly proposing other changes to the

9 DSM program administrations.

10 Q Going back to your, I guess, direct

11 testimony in your discussion of injuries and damages,

12 your column O adjustment --

13 A What page?

14 Q Page 18, line 2.

15 A Yes.

16 Q -- what the Company is proposing is a

17 restating adjustment replacing the accrual with a

18 six-year rolling average of actual injuries of accounting

19 for damage payments not covered by insurance. This is a

20 reserve account, reserve method of accounting for

21 injuries and damages net of insurance proceeds?

22 A Right. We use that for financial

23 accounting purposes as well, the six-year average. This

24 was just a correction of the accrual.

25 Q Are any costs other than the amounts in the

691

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 injuries and damages six-year rolling average for the ice

2 storm of '96 included in the test year?

3 A Yes.

4 Q And what are those costs?

5 A Are there other injuries and damages

6 included in the adjustment outside of the ice storm?

7 Q Outside of the injuries and damages

8 adjustment, are there any costs associated with the ice

9 storm included in the test year?

10 A To the best of my knowledge, no.

11 Q Is the level of storm damage included in

12 the six-year average a reflection of ongoing expenses?

13 A Storm damage expenditures aren't actually

14 included in the adjustment, they're part of our regular

15 O&M expenditures, they're part of our operating expenses

16 outside of injuries and damages. The only storm damage

17 that's included, storm damage-related costs that are

18 included, in the injuries and damages is specifically ice

19 storm. Our regular, ongoing storm damage costs are

20 captured in our regular O&M accounts.

21 Q You would agree that it's generally

22 appropriate to remove expenses that are extraordinary and

23 non-recurring?

24 A I would agree that non-recurring,

25 extraordinary items can be excluded.

692

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 Q On page 11, lines 18 through 20 of your

2 rebuttal testimony you state, "Additionally, storm

3 damages of this level" --

4 A Could you just give me one minute? I'm

5 having a hard time going back and forth.

6 MR. MEYER: Say that again, please.

7 MR. WOODBURY: Page 11 of his rebuttal

8 testimony, line 18.

9 MR. MEYER: Okay, thanks.

10 THE WITNESS: Page 11, line 18?

11 Q BY MR. WOODBURY: Yes.

12 A Okay.

13 Q You state, "Additionally, storm damages of

14 this level are not unprecedented and it cannot be

15 guaranteed that they will not reoccur." Did the Company

16 issue a publication, Ice Storm '96 Overview, two months

17 later?

18 A I think we did, yes.

19 Q This [indicating]?

20 A Yes, I recall that.

21 Q Okay, and in that publication, it states on

22 page 4, "The National Weather Service categorized this

23 ice storm as the only event of its kind in 115 years of

24 record," and on page 8, "No comparable ice storm has

25 occurred since the recording of weather statistics," so I

693

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 guess I ask, which storm has occurred that has set a

2 precedent for this ice storm?

3 A Well, I guess that should be corrected.

4 What I meant there was storm damages of this level are

5 not unprecedented in the utility industry. On our

6 system, yes, it was unprecedented. At the same time, I

7 wanted to state that they are viable utility operating

8 costs that will happen from time to time on -- our system

9 doesn't show it. You see more of it in the East Coast or

10 hurricane-related groups, but they are viable operating

11 utility costs.

12 Q The six-year rolling average that was

13 approved by the Washington Commission, was that initially

14 approved in the Puget Sound case, to your knowledge?

15 A I don't know who came first.

16 Q And in that case, the Washington Commission

17 stated, "We adopt Staff's recommendation to use a

18 normalized level for storm damage. The amount used

19 should be based on a six-year average to somewhat dampen

20 weather variability, to accommodate the current PRAM

21 mechanism and to reflect the intention that general rate

22 cases be filed every three years."

23 Is it the Company's intention in Idaho to

24 file a rate case every three years?

25 A That's not a stated policy that I'm aware

694

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 of.

2 Q Is it your understanding that in the State

3 of Washington that the reason the commission approved

4 that is because there would be that periodic type of

5 filing?

6 A I'm not aware.

7 Q The Commission basis filings that you make

8 with Idaho and with some of your other jurisdictional

9 states, you've been making those since '94?

10 A I think we've been making them since 1990.

11 It was my understanding that that was a Washington rule

12 that was put in place and that we have an agreement with

13 the Staff, with the Idaho Staff, to provide them as well.

14 Q Is it your understanding that the periodic

15 Commission basis filings comport generally with the

16 restated total that appears in your Exhibit 11, column F,

17 page 6, rather than the pro forma total that appears in

18 that same exhibit?

19 A Could you restate that question, please?

20 Q Yes. Is it your understanding that the

21 periodic Commission basis filings which the Company files

22 with us that they comport generally or more closely with

23 the restated total which occurs in your Exhibit 11,

24 column F, page 6, rather than the pro forma total which

25 appears at Exhibit 11, page 8?

695

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 A We're on Exhibit 11?

2 Q Uh-huh.

3 A And you're referring to column F?

4 Q Yes, column F, Exhibit 11.

5 A Or are you referring to column R?

6 Q I think it's "f."

7 A I think it's "r."

8 Q Well, the restated total more than your

9 pro forma total.

10 A Actually, that number does not reflect what

11 would be filed in our Commission basis reports because it

12 doesn't include the power supply adjustment in PF1, it

13 doesn't include the synchronization adjustment in PF2, it

14 doesn't include a weather adjustment in PF3. The number

15 for our Commission basis in the same period that would

16 comport or compare to the 9.65 is actually 7.90.

17 My original goal when we filed the case was

18 to take our Commission basis report as the starting

19 point, which would be at 7.9, and then add pro forma or

20 refining adjustments. We would have refined the weather

21 adjustment, we moved the time for the pro forma, but it

22 became confusing. We would have had two power supply

23 adjustments, we would have had two weather adjustments,

24 so we backed them out entirely to get a different

25 restated basis, so the 7.9 is the Commission basis report

696

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 rate of return for this time period.

2 Q Okay.

3 A And that compares to our pro forma number

4 of 6.94, so the pro forma adjustments took us from the

5 Commission basis 7.9 to the pro forma of 6.94.

6 Q Thank you. In your rebuttal testimony on

7 page 6, speaking of the balancing account --

8 A I'm on page 6.

9 Q -- you start there speaking of the

10 balancing account and then on page 7, line 12, you

11 propose using Account 253 to accumulate the differences

12 in O&M level cost rates and the annual costs actually

13 spent?

14 A Yes, just a deferred debit balancing

15 account.

16 Q Does Avista plan on using subaccounts

17 within this account so these differences are totally

18 separate from any other items that Account 253 may be

19 used for?

20 A Absolutely. There will be no commingling

21 of the hydro relicensing balancing account with any other

22 dollars in Account 253.

23 Q Isn't it true that with separate

24 subaccounts the hydro relicensing balancing account would

25 be completely separated from the PCA?

697

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 A Absolutely.

2 Q Could you explain how costs are allocated

3 or directly assigned to Idaho? It's direct assignment

4 based on cost causation, then allocation using the four

5 factor formula; is that your understanding?

6 A You have the option of a direct assignment

7 of a cost and then outside of that you utilize

8 allocation. You can either directly assign to Idaho or

9 you put it in an account that allocates it to Idaho.

10 Q Okay, and can you explain, are there any

11 differences for the resource optimization department

12 discussed yesterday by Mr. Norwood as far as allocation?

13 A Are there any differences? They have the

14 same options. They can directly assign costs or they can

15 include it in an account that gets allocated.

16 Q Okay. Mr. Ward introduced an Exhibit 211

17 which was Deloitte and Touche, do you have that?

18 A Yes.

19 Q Looking at page, I guess, the second page

20 to that, regarding Centralia, column 7, there's a paren,

21 (25.9), could you indicate what that is, the terminal net

22 salvage?

23 A The column title is Terminal Net Salvage

24 Value which would have to be the net costs associated

25 with closing Centralia down, selling off the salvageable

698

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 parts and netting the decommissioning or cost of removal

2 against it.

3 Q Would you agree that the most likely

4 occurrence regarding the Centralia is for that sale to be

5 completed?

6 A I don't know. I would defer that question.

7 Q If the sale were completed, would it be

8 appropriate to remove the depreciation calculation

9 indicated on this page?

10 A There would be a number of changes if the

11 sale was actually completed.

12 Q Would this be one of them?

13 A Depreciation, rate base, fuel costs, it

14 would be a fairly detailed study to eliminate all the

15 costs associated with Centralia.

16 Q But you would agree that this would be --

17 A I would agree depreciation is a component

18 of Centralia's costs, yes.

19 MR. WOODBURY: Thank you, Mr. Falkner.

20 Madam Chair, I have no further questions.

21 COMMISSIONER SMITH: Thank you,

22 Mr. Woodbury.

23 Do we have questions from the Commission?

24 I have one.

25

699

CSB REPORTING FALKNER (X)
Wilder, Idaho 83676 Avista

1 EXAMINATION

2

3 BY COMMISSIONER SMITH:

4 Q You were discussing earlier with

5 Mr. Woodbury the interest rates on page 14 of your

6 rebuttal.

7 A Yes.

8 Q One of my thoughts was wouldn't the

9 Commission-approved Company overall rate of return be

10 another choice?

11 A That is an option, yes. Generally, the

12 overall cost of capital is applied to longer-lived timing

13 differences, plant balances. The way I view the

14 differences in the recovery of DSM costs and expenditures

15 is it's more of a cash flow timing difference similar to

16 the PGA balancing account in our gas system.

17 COMMISSIONER SMITH: All right, thank you.

18 Mr. Meyer, do you have any redirect?

19 MR. MEYER: I do, thank you.

20

21

22

23

24

25

700

CSB REPORTING FALKNER (Com)
Wilder, Idaho 83676 Avista

1 REDIRECT EXAMINATION

2

3 BY MR. MEYER:

4 Q You were asked by counsel for Potlatch to

5 refer to page 4 of your direct testimony consisting of a

6 bar graph for a number of prior years.

7 A Yes.

8 Q Do you have that in front of you?

9 A No.

10 Q I'm already not getting the answers I

11 need.

12 A I'm there.

13 Q Okay. Now, you were asked to do some quick

14 calculations or agree essentially, subject to check, to

15 the certain averaging of those results over time and then

16 I believe you were asked to compare the average of those

17 Commission basis results with the requested return in

18 this case. Do you recall that exchange?

19 A Yes, I do.

20 Q Now, define for me the difference between a

21 Commission basis portrayal on this bar chart and a fully

22 pro formed portrayal as reflected in our revenue

23 requirements case.

24 A The Commission basis is an interim

25 reporting mechanism that we utilize starting with our

701

CSB REPORTING FALKNER (Di)
Wilder, Idaho 83676 Avista

1 actual jurisdictionally-allocated results of operations

2 that tie directly to our general ledger. We go through

3 and we implement previously authorized Commission

4 decisions to normalize, to adjust the actuals. We

5 adjust, we normalize weather, we normalize power supply

6 on more of an estimated, quicker basis than we do in the

7 pro forma.

8 In pro forma reviews, we go outside the

9 test period to the period specifically for the power

10 supply adjustment where we look to take known and

11 measurable changes based on contracts, not only for power

12 supply, but for, for example, wages and salaries.

13 Q And certain of those pro forming

14 adjustments that go beyond the so-called Commission basis

15 reporting adjustments, certain of those as proposed by

16 the Company were concurred with by the Staff in this

17 case; correct?

18 A Yes.

19 Q So it's not as if Staff itself necessarily

20 adheres exactly to a Commission basis for putting their

21 own case together; correct?

22 A Correct. Generally, when we file the

23 Commission basis reports the cover letter states that

24 it's the Company's option to include adjustments that are

25 different than contained in the Commission basis.

702

CSB REPORTING FALKNER (Di)
Wilder, Idaho 83676 Avista

1 Q So if one had fully pro formed as is the

2 custom these results in each of these prior years, would

3 you expect the demonstrated returns to have been lower

4 than what is shown on this page 4?

5 A Yes, they would be. In fact, there have

6 been previous years where we filed, the reports we

7 provided the Idaho Staff and the Washington Staff has a

8 Commission basis number and them we do a pro forma as

9 well. Generally, the largest adjustment would be the

10 power supply and they have all been lower than what is

11 represented on this graph.

12 Q Thank you. There was some discussion

13 surrounding the reference to depreciation as it relates

14 to "shareholder profits"; do you recall that exchange?

15 A Yes, I do.

16 Q And I believe that any uncertainty or any

17 confusion surrounding whether shareholder profits meant

18 additional earnings as opposed to something else, that

19 was explored and we're not talking about that here in

20 connection with depreciation is driving additional

21 earnings, are we?

22 A No, depreciation is not driving additional

23 earnings.

24 Q Nor do you understand Potlatch to contend

25 such?

703

CSB REPORTING FALKNER (Di)
Wilder, Idaho 83676 Avista

1 A Correct.

2 Q So then the question reduced to --

3 A I didn't plan that.

4 (Pause in proceedings.)

5 Q BY MR. MEYER: So acceptance of any revenue

6 requirement in this case associated with the depreciation

7 adjustment will not serve to increase earnings, per se?

8 A It will not increase corporate earnings,

9 correct.

10 Q Okay. Now, then if shareholder profits --

11 strike that. So if it does not increase earnings,

12 per se, it won't provide additional earnings to pay

13 dividends as such, will it?

14 A It will not provide additional earnings to

15 pay dividends, correct.

16 Q So if shareholders somehow benefit

17 indirectly from this, would it be through stock

18 appreciation in price?

19 A Shareholders are going to benefit directly

20 from either dividends or stock appreciation.

21 Q But a great many things contribute to stock

22 appreciation; isn't that correct?

23 A Yes, it is correct.

24 Q Many of which have no relationship

25 whatsoever to revenue requirements established in this

704

CSB REPORTING FALKNER (Di)
Wilder, Idaho 83676 Avista

1 case by this Commission?

2 A Correct.

3 Q However, the revenue requirement

4 established by this Commission in this case is an element

5 that the investment community does consider?

6 A Absolutely.

7 Q But of that set of considerations, the cash

8 flow provided by the depreciation adjustment is only one

9 element of many that drives this ratemaking process;

10 correct?

11 A Correct.

12 Q And so any other pro forma adjustment that

13 this Commission might accept in this case that might

14 serve to increase revenue requirement might also be

15 favorably received by the investment community; correct?

16 A Correct.

17 Q With regard to your brief discussion on ice

18 storm, is there any suggestion in the testimony that

19 you've read of other parties that the ice storm costs

20 themselves were somehow imprudent or unnecessary?

21 A No.

22 Q And if these costs are not reflected

23 through the vehicle of this six-year averaging for

24 injuries and damages, will the Company be allowed to

25 recover those arguably necessary and prudent costs?

705

CSB REPORTING FALKNER (Di)
Wilder, Idaho 83676 Avista

1 A No.

2 Q The question of intergenerational equity

3 was discussed in connection with the relicensing

4 expenditures. Do you recall that?

5 A Yes, I do.

6 Q And is it your testimony that these

7 relicensing costs related to the continued operation of

8 the plants?

9 A Yes, that's my testimony.

10 Q And is it your testimony that these plants

11 or that these costs as we speak are being incurred?

12 A The settlement has been agreed to, it has

13 been implemented. It was an integral rationale for, the

14 early implementation was an integral rationale for, the

15 settlement itself to get the -- and again, Mr. LaBolle

16 can speak more to the detail on that.

17 Q But to the best of your knowledge, we are

18 not awaiting the actual issuance of the FERC license to

19 begin spending these dollars, are we?

20 A No. The settlement agreement is basically

21 an operational agreement that allows continued operation

22 and flexibility of the Clark Fork projects.

23 Q And Mr. LaBolle, a later witness, can speak

24 to the current benefits derived from those expenditures;

25 correct?

706

CSB REPORTING FALKNER (Di)
Wilder, Idaho 83676 Avista

1 A Yes.

2 Q Many other investments the Company makes

3 from time to time, whether expense or capital, relate to

4 plants or facilities that have relatively long, useful

5 lives; isn't that correct?

6 A Correct. Modifications and improvements

7 are continually made to long-lived assets to maintain

8 their current life or to extend their life.

9 Q Okay. Now, in terms of intergenerational

10 equity, when current rates reflect expenditures for a

11 long-lived asset, does the Commission in its exercise of

12 judgment factor in intergenerational equity to the best

13 of your knowledge?

14 A To the best of my knowledge,

15 intergenerational equity is a component of the decision.

16 Q But the Commission notwithstanding the

17 consideration of intergenerational equity still allows

18 for recovery through rates at present for costs

19 associated with long-lived assets, some of which may have

20 a 40- to 50-year useful life?

21 A Yes.

22 MR. MEYER: Okay. That's all I have.

23 Thank you.

24 COMMISSIONER SMITH: Thank you,

25 Mr. Meyer, and thank you, Mr. Falkner.

707

CSB REPORTING FALKNER (Di)
Wilder, Idaho 83676 Avista

1 THE WITNESS: Thank you.

2 (The witness left the stand.)

3 COMMISSIONER SMITH: This looks like this

4 would be a good time for a ten-minute break.

5 (Recess.)

6 COMMISSIONER SMITH: I think, Mr. Meyer,

7 we're ready for your next witness.

8

9 LARRY LaBOLLE,

10 produced as a witness at the instance of Avista

11 Corporation, having been first duly sworn, was examined

12 and testified as follows:

13

14 DIRECT EXAMINATION

15

16 BY MR. MEYER:

17 Q Are you ready?

18 A Yes.

19 Q For the record, please state your name and

20 your employer.

21 A My name is Larry LaBolle. I work for

22 Avista Corporation in Spokane, Washington.

23 Q Have you prepared rebuttal testimony in

24 this proceeding?

25 A I have.

708

CSB REPORTING LaBOLLE (Di)
Wilder, Idaho 83676 Avista

1 Q Do you have any changes to make to that?

2 A I do not.

3 Q Are you also sponsoring what has been

4 marked as Exhibit No. 25?

5 A Yes, I am.

6 Q Do you have any changes to make to that?

7 A I do not.

8 Q Is the information contained therein true

9 and correct?

10 A It is.

11 MR. MEYER: With that, I ask that

12 Mr. LaBolle's rebuttal testimony be entered into the

13 record as if read and move for the admission of

14 Exhibit 25.

15 COMMISSIONER SMITH: If there's no

16 objection, the prefiled testimony will be spread upon the

17 record as if read and Exhibit 25 will be admitted.

18 (Avista Corporation Exhibit No. 25 was

19 admitted into evidence.)

20 (The following prefiled rebuttal

21 testimony of Mr. Larry LaBolle is spread upon the

22 record.)

23

24

25

709

CSB REPORTING LaBOLLE (Di)
Wilder, Idaho 83676 Avista

1 Q What is your name, business address, and

2 permanent position?

3 A My name is Larry LaBolle. I am the

4 Relicensing Manager in the Hydro Licensing and Safety

5 Department at Avista Corp., 1411 E. Mission Avenue,

6 Spokane, Washington.

7 Q Have you previously submitted direct

8 testimony in this proceeding?

9 A No.

10 Q Please summarize your education and

11 experience.

12 A I have both Bachelors and Masters degrees

13 in fisheries sciences. While working as a biologist and

14 Regional Fishery Manager for the Idaho Department of Fish

15 and Game, I led the environmental evaluations of several

16 preliminary permits and applications for new licenses.

17 Since joining the Company in 1990, I have worked on

18 several license amendments and, since 1993, have managed

19 the Company's Clark Fork relicensing program.

20 Q What is the scope of your rebuttal

21 testimony in this proceeding?

22 A My testimony in this proceeding responds to

23 the testimony of Staff witness Mr. Lobb regarding

24 adjustments to hydro relicensing expenses as presented on

25 page 17, 18, 19 and 21 of his testimony, and that of

710

LaBolle, Di-Reb 1
Avista

1 Potlatch Corporation witness Mr. Peseau as presented on

2 pages 24 through 26 of his testimony under the caption,

3 "Clark Fork Relicensing Costs."

4 Q What is your response to the adjustments

5 proposed by Mr. Lobb?

6 A I understand Mr. Lobb's position is to not

7 allow a portion of the relicensing implementation costs

8 because, from the Commission's perspective, these costs

9 do not have a history and therefore are not considered to

10 be known and measurable. However, in

11

12 /

13

14 /

15

16 /

17

18

19

20

21

22

23

24

25

711

LaBolle, Di-Reb 1A
Avista

1 support of Mr. Falkner's testimony in this hearing in

2 which Mr. Falkner proposes a balancing account method to

3 address this issue, I am presenting the relicensing

4 expenses in a manner that reflects our most recent

5 estimate of the expense items in the final Clark Fork

6 Settlement Agreement. The cost data presented by Avista

7 Corp. and shown in Exhibit No. 104 of Mr. Lobb's

8 testimony was submitted on October 28, 1998 and was of a

9 preliminary nature. The expense items I am presenting

10 will more accurately represent our assessment of the

11 expense costs associated with the Clark Fork Settlement

12 Agreement.

13 Q Would you present the hydro relicensing

14 expenses that should be included in Mr. Falkner's

15 approach to establishing a balancing account?

16 A Yes. I have included in Exhibit 25 the

17 expense costs associated with those Protection,

18 Mitigation, and Enhancement (PME) measures that have an

19 expense component. This breakdown represents my best

20 assessment of the funds to be spent on non-capital items

21 such as studies, plans, monitoring, labor, consultants,

22 contract labor, travel, lodging, benefits, maintenance

23 and operations pursuant to the Final Settlement

24 Agreement.

25 Q How do you intend to address the one time

712

LaBolle, Di-Reb 2
Avista

1 and periodic expenditures?

2 A One time and periodic expenditures are not

3 included initially in the annual expense recovery

4 proposed by the Company. Operation and maintenance

5 expenditure levels different than what are allowed in

6 this case would be captured in the balancing mechanism

7 proposed by Witness Don Falkner.

8 Q What is the Company's request for a hydro

9 relicensing pro forma adjustment?

10 A The pro forma adjustment is derived from

11 the total of the expense column less the existing and

12 ongoing costs, as shown in Exhibit 25. This total

13 represents the

14

15 /

16

17 /

18

19 /

20

21

22

23

24

25

713

LaBolle, Di-Reb 2A
Avista

1 incremental expenses associated with implementation of

2 the Clark Fork Settlement Agreement. The total for the

3 Clark Fork Settlement Agreement annual expense adjustment

4 is $1,861,820.

5 Q What is your response to the argument made

6 by Mr. Peseau that rate recovery by Avista Corp. should

7 not begin until FERC issues a new license order for the

8 Clark Fork Projects?

9 A The Clark Fork Settlement Agreement is an

10 unprecedented success in the arena of the FERC's

11 regulation of hydropower, and represents an achievement

12 of tremendous benefit to present and future Avista Corp.

13 electric customers.

14 Avista Corp. developed an alternative approach

15 that was intended to avoid the lengthy uncertainty of a

16 contested case, and more importantly, create the

17 opportunity for the Company to negotiate terms of an

18 agreement that would minimize the impact on our

19 customers' rates. The dollars at issue will be spent in

20 advance of a new license and represent known and

21 measurable amounts.

22 Q Would you please summarize this process?

23 A Yes. In the big picture, our task focused

24 on creating an effective negotiating environment for all

25 parties, and establishing the goal of a comprehensive,

714

LaBolle, Di-Reb 3
Avista

1 pre-filing Settlement Agreement. The purpose of the

2 Agreement was to provide incentive for the parties to

3 negotiate in good faith, and to create a sense of urgency

4 in the process. Our effort, which is now known

5 nationally as the Living License, established the

6 template for what has become an entirely new approach to

7 relicensing, namely FERC's Collaborative Alternative.

8 Q What has been the immediate outcome of this

9 process?

10

11 /

12

13 /

14

15 /

16

17

18

19

20

21

22

23

24

25

715

LaBolle, Di-Reb 3A
Avista

1 A Avista Corp. secured the first-ever direct

2 participation of FERC staff in first and second-stage

3 consultation, formed the first national non-governmental

4 organization partnership to effectively bridge local,

5 regional, and national interests, restructured with

6 FERC's support the NEPA compliance process, executed the

7 first-ever Collaboratively-Prepared Environmental

8 Assessment, and effectively melded agency mandatory

9 conditioning with a collaborative, consensus-based

10 process. Last year Avista Corp. was sponsored by FERC to

11 speak on their behalf at national outreach meetings

12 around the nation about the structure of the Living

13 License process, its benefit to the Company and

14 customers, and its application as a national model under

15 FERC's new alternatives.

16 Finally, of course, Avista Corp. and the

17 relicensing parties achieved our goal of a comprehensive,

18 pre-filing Settlement Agreement, the first of its kind in

19 the nation. And because FERC staff participated formally

20 throughout the entire process, because the Clark Fork

21 Living License has been adopted as the FERC's

22 Collaborative Alternative, because all parties prepared a

23 consensus NEPA document, and because staff of FERC's

24 Office of General Counsel participated in the development

25 of the Settlement Agreement, we expect a new license not

716

LaBolle, Di-Reb 4
Avista

1 only on time, but very likely by the end of this year.

2 Q What is your conclusion?

3 A Avista Corp. customers, both present and

4 future, benefit from the Clark Fork Settlement Agreement,

5 and should pay now for the prudent undertaking of Avista

6 Corp. to reach and implement this agreement. Present

7 customers benefit directly because Avista Corp. can now

8 plan today with certainty how to meet future customer

9 resource capacity requirements at the lowest possible

10 cost. Future customers benefit because there is no

11 continued accrual of AFUDC, which only serves to increase

12 their revenue requirement -

13

14 /

15

16 /

17

18 /

19

20

21

22

23

24

25

717

LaBolle, Di-Reb 4A
Avista

1 future being anywhere from 6 to 21 months from today,

2 when Avista will have either been granted a new license

3 or an annual license. Further, the way in which the

4 agreement was reached with the participation of FERC

5 staff dramatically increases the likelihood of speedy

6 application processing and the issuance of a new license

7 order for the Clark Fork Projects. And finally, the more

8 uniform allocation of lower overall costs among present

9 and future electric customers benefits all Avista Corp.

10 customers and the health of our region as a whole.

11 Q Does that conclude your rebuttal testimony?

12 A Yes, it does.

13

14

15

16

17

18

19

20

21

22

23

24

25

718

LaBolle, Di-Reb 5
Avista

1 (The following proceedings were had in

2 open hearing.)

3 MR. MEYER: And the witness is available

4 for cross.

5 COMMISSIONER SMITH: Okay, how about

6 Mr. Woodbury, do you want to start this time?

7 MR. WOODBURY: Sure.

8

9 CROSS-EXAMINATION

10

11 BY MR. WOODBURY:

12 Q Good morning, Mr. LaBolle.

13 A Good morning, Scott.

14 Q You have a familiarity with the Clark Fork

15 settlement agreement?

16 A Yes, I do.

17 Q Anywhere in that agreement does it specify

18 the amount of money that the Company will commit to

19 annual administration of the license?

20 A It's referenced in what's known as

21 Appendix U to the settlement agreement which is a tabular

22 display of the Company's relicensing obligation costs.

23 The administration of the license implementation there is

24 identified to be $1.39 million per year.

25 Q In your original rate filing in this case,

719

CSB REPORTING LaBOLLE (X)
Wilder, Idaho 83676 Avista

1 you identify 1.16 million as the cost of administration

2 of the license?

3 A I believe that's the case.

4 Q And then in your rebuttal, you indicated

5 1.39 as you just did?

6 A Yes.

7 Q How did that 20 percent increase occur?

8 A Well, there are several variations between

9 what we first submitted for relicensing costs and what

10 have been submitted in my exhibit and it's particularly

11 because the relicensing costs had not been finalized at

12 the time we sent these costs in to support this case and,

13 of course, by this time they have been and that

14 settlement agreement has been implemented, so it was

15 simply a refinement on a consensus basis, really the

16 basis by which all of these costs are derived, of what it

17 would cost Avista Corporation to fully implement the

18 terms and conditions of the settlement agreement.

19 Q And is the 1.39 million, is that a cap?

20 A It is not a cap. It is actually -- 93

21 percent is driven directly to salaries, overheads and

22 office facilities. It is for the implementation which

23 will take ten full-time people and seven part-time

24 people, staff of both Avista and three of the natural

25 resource agencies.

720

CSB REPORTING LaBOLLE (X)
Wilder, Idaho 83676 Avista

1 About seven percent of that total is what I

2 call a variable estimate for legal fees and for

3 consultant fees, but it is not fixed. If in fact we get

4 into implementation years down the road and find that it

5 takes a greater or a lesser staff commitment than what's

6 been provided for here, then that number will change, but

7 for now it is 93 percent allocated to positions which

8 have been or are currently being filled.

9 Q All right. If the balancing, if a

10 balancing account methodology is established as proposed

11 by the Company, what controls the amount of expenditures

12 that can occur annually to administrate the program?

13 A What controls what will be spent?

14 Q Yeah. Are there any set of controls?

15 MR. MEYER: Are you asking, Mr. Woodbury,

16 whether the balancing account itself has controls built

17 into it or are you asking this witness from an

18 operational standpoint about anticipated expenditure

19 levels going forward?

20 Q BY MR. WOODBURY: I'm inquiring as to

21 whether the amount that is expended is, there are any

22 controls or any controls is an inartful -- are there any

23 limits or any guidelines as far as, you know, the amounts

24 that can be expended within the program or are we talking

25 clearly that that 1.39 million is essentially the amount

721

CSB REPORTING LaBOLLE (X)
Wilder, Idaho 83676 Avista

1 that's established and the Company will attempt to keep

2 its budget within that limit and essentially perform in

3 accordance with the terms?

4 A I referenced just a moment ago that the

5 estimate for the costs of administering the

6 implementation is 1.39 million. I mentioned that it's a

7 consensus estimate. The settlement agreement is made up

8 of 27 formal parties, formally identified parties. Of

9 course, there are many, many resource agencies in there

10 who have the expertise of knowing what it takes from a

11 human resource perspective to implement various natural

12 resource programs and so the collective knowledge of that

13 body identified these sets of positions and their

14 attendant costs and then the resulting 1.39 million as

15 the most reasonable estimate of what it would cost to

16 do.

17 Now, there aren't specific limits outside

18 of that that govern how much money would be spent more or

19 less than that and the Company will endeavor in any

20 respect and in every respect to spend less than that if

21 we can fully meet our obligations under the settlement

22 agreement and eventually under compliance with the terms

23 of the FERC license and do that effectively and spend

24 less money. We'll always try to do that.

25 Q I guess what I was wondering is whether

722

CSB REPORTING LaBOLLE (X)
Wilder, Idaho 83676 Avista

1 there will be any safeguards for the customers inasmuch

2 as they will be paying for this that the monies are spent

3 judiciously, prudently and that the Company does not see

4 this as sort of a cash cow, I guess, or something, that's

5 a bad word, also, but --

6 MR. MEYER: Are you asking, Mr. Woodbury,

7 whether this witness --

8 COMMISSIONER SMITH: Mr. Meyer, if you have

9 a question, would you address the Chair?

10 Q BY MR. WOODBURY: What restraints or

11 controls within Avista are there with respect to

12 relicensing costs that are incurred administratively?

13 A All the relicensing costs that are going to

14 be tied to the implementation?

15 Q Yeah.

16 A Under the settlement agreement, there are

17 really two components. One is what we call the costs

18 that drive the implementation of protection, mitigation

19 and enhancement measures, PM&E's for short, and then

20 there are these administrative and implementation costs

21 that we're talking about. The PM&E costs represent on

22 average, it's a rough levelized cost, about $3.3 million

23 per year.

24 Of that $3.3 million, 94 percent of those

25 costs are fixed annual obligations of the Company as

723

CSB REPORTING LaBOLLE (X)
Wilder, Idaho 83676 Avista

1 defined by the settlement agreement. 6 percent of those

2 costs are consensus estimates of what it may cost with

3 the knowledge that there may be some variation around

4 those consensus estimates, so again, fully 94 percent of

5 the costs are controlled by the settlement agreement.

6 That is the value of the settlement agreement to the

7 customer and to the Company is that we've confined our

8 costs and provided a basis through the implementation

9 mechanism to effectively manage within those costs.

10 Q And when you say a consensus estimate,

11 that's of the signatories to the agreement?

12 A Yes, and the various technical parties that

13 supported that settlement agreement.

14 MR. WOODBURY: Thank you.

15 Madam Chairman, I have no further

16 questions.

17 COMMISSIONER SMITH: Mr. Ward, do you have

18 questions?

19 MR. WARD: Yes.

20

21 CROSS-EXAMINATION

22

23 BY MR. WARD:

24 Q Mr. LaBolle, would you turn to page 4 of

25 your testimony? At the bottom of the page you have an

724

CSB REPORTING LaBOLLE (X)
Wilder, Idaho 83676 Avista

1 answer there at lines 18 through 23, I want to ask you a

2 question about that, but before I do, you agreed early on

3 in your testimony that the dollars at issue will be spent

4 in advance of a new license, did you not?

5 A Some of the dollars will be spent in

6 advance of the new license, the implementation dollars

7 which are being spent right now beginning March 1st up

8 and to the time the license is received.

9 Q I'm asking you specifically about the

10 dollars that are in dispute, that is, the O&M costs being

11 paid now, that's in advance of the license; is that

12 correct?

13 A I believe that's correct.

14 Q All right. I only have really one question

15 for you. If you'd read through to yourself the lines on

16 18 through 23 down through the word "AFUDC" -- well, just

17 down through the end of 18 through 23.

18 A Uh-huh.

19 Q Now, let me ask you if in the first line,

20 first and second line, we substituted the word, the words

21 "the Clark Fork Settlement Agreement" with the words

22 "construction work in progress," wouldn't that be

23 exactly the argument made on behalf of construction work

24 in progress in rate base by its proponents?

25 MR. MEYER: I object. This witness is not

725

CSB REPORTING LaBOLLE (X)
Wilder, Idaho 83676 Avista

1 put forward as an accounting witness who is at all

2 familiar with the concept of construction work in

3 progress. That issue of construction work in progress is

4 a combination legal/accounting issue. That's not what

5 this witness is here to testify about.

6 COMMISSIONER SMITH: Mr. Ward.

7 MR. WARD: Well, let me ask one question in

8 response and then I'll withdraw it if he has no

9 knowledge.

10 COMMISSIONER SMITH: All right.

11 Q BY MR. WARD: Mr. LaBolle, do you have any

12 working knowledge of the arguments for and against the

13 inclusion of construction work in progress in rate base?

14 A Mr. Ward, I do not.

15 MR. WARD: Thank you, I'll withdraw the

16 question.

17 COMMISSIONER SMITH: Thank you.

18 Mr. Shurtliff.

19

20 CROSS-EXAMINATION

21

22 BY MR. SHURTLIFF:

23 Q In that same paragraph, I'm intrigued by

24 the second sentence there, "Present customers benefit

25 directly because Avista Corp. can now plan today with

726

CSB REPORTING LaBOLLE (X)
Wilder, Idaho 83676 Avista

1 certainty how to meet future customer resource capacity

2 requirements at the lowest possible cost." Now, my

3 question, sir, is why do present customers today care a

4 whit about -- what level of comfort do they get from that

5 that's equateable to dollars?

6 A I'd be happy to explain that,

7 Mr. Shurtliff.

8 Q Thank you.

9 A The Cabinet Gorge and Noxon Rapids projects

10 located conveniently just about 40 miles from here are

11 power peaking facilities. They have an average annual

12 generation of 320 megawatts, but they have a capacity of

13 790 megawatts. We store water in the reservoirs at

14 night, release that during the day, generate at or near

15 that capacity for significant times during the day. They

16 provide a significant part of our electrical capacity and

17 ability to meet daily customer demand.

18 In a relicensing, which by itself is very

19 contentious and which I'd love to talk for maybe two or

20 three hours about it with you, but I've been instructed

21 not to be effervescent about this whole issue, in

22 relicensing, the thing that people go after, the natural

23 resource agencies and the river conservation interests,

24 is this flexibility in operation; that is, running the

25 river up and down on a daily basis to follow load.

727

CSB REPORTING LaBOLLE (X)
Wilder, Idaho 83676 Avista

1 If we were to have a run of river condition

2 placed upon us, we would lose at various times of the

3 year up to 400 megawatts of capacity. That happened just

4 upstream from us at the Kerr project where the Department

5 of Interior, one of the many parties with mandatory

6 conditioning authority, that is, the unilateral authority

7 to mandate terms and conditions to the license above and

8 beyond anything the FERC can do about it, they took away

9 all of the power peaking capability of the Kerr project.

10 Those were the initial proposals of the

11 agencies that came together with us, so as we first came

12 together, the State of Idaho and the State of Montana,

13 both who have this unilateral mandatory condition and

14 authority to mandate terms and conditions, were proposing

15 to make these projects run of river or near run of

16 river.

17 Of course, what that does for our resource

18 planning people is they say how are we going replace 400

19 megawatts, at least during certain times of the year 400

20 megawatts, of capacity and that gets the wheels rolling

21 about how you're going to do that, and as you get closer

22 and closer to the point at which a license would be

23 issued or certainly that the issues surrounding

24 operations would be defined, the Company is going to have

25 to undertake a means to acquire those resources.

728

CSB REPORTING LaBOLLE (X)
Wilder, Idaho 83676 Avista

1 If the customers today didn't have the

2 certainty of a settlement agreement which binds the

3 parties to the support of the operation means defined in

4 the settlement agreement, the Company would have to

5 provide for future resources to take care of those

6 capacity losses that would have occurred or the

7 uncertainty that those might have occurred and there

8 would be a cost to customers. Even before the license

9 was issued, there would be a cost. I cannot define how

10 big that cost would be, but the fact that we have

11 certainty around the power peaking capacity of the

12 resources today provides benefit to customers today.

13 That's my argument.

14 Q There would be a cost to today's customers

15 to make those changes?

16 A That's right. If you wait until you get

17 the new license and, of course, most parties get a new

18 license from FERC without knowing how it's going to come

19 out, you can't wait until you get the license which is

20 the day that you begin your new restricted operations to

21 figure out how you're going to replace 400 megawatts of

22 capacity. That planning has to be done in advance and

23 there's a cost associated with that planning regardless

24 of how it occurs, but certainly variable to the extent to

25 which it does occur in a real facility sense.

729

CSB REPORTING LaBOLLE (X)
Wilder, Idaho 83676 Avista

1 Q Indeed, if you were to anticipate that, you

2 might need to create some other kind of generation, for

3 example, would that be what you're saying?

4 A Either actually buy, acquire, purchase

5 contracts or do the planning for the development of

6 future generation, things like that, that's correct.

7 Q And in response to the question put to you

8 by Mr. Ward, you're not familiar with the concept of

9 construction work in progress?

10 A That is correct. I'm not at all familiar

11 with that term.

12 MR. SHURTLIFF: All right, well, you've

13 just defined it, then. I have no further questions.

14 THE WITNESS: I just defined it?

15 COMMISSIONER SMITH: Thank you,

16 Mr. Shurtliff.

17 Do we have questions from the Commission?

18 Any redirect, Mr. Meyer?

19 MR. MEYER: I do.

20

21 REDIRECT EXAMINATION

22

23 BY MR. MEYER:

24 Q You were asked in one fashion or another by

25 Mr. Shurtliff about benefits to current customers

730

CSB REPORTING LaBOLLE (Di)
Wilder, Idaho 83676 Avista

1 resulting from the expenditures of these dollars. Can

2 you provide a couple of illustrative examples of costs

3 that we might at present be incurring that we are not

4 incurring because of the settlement?

5 A I can. As many of you know, the Bull Trout

6 was listed, placed upon the endangered species list as

7 threatened, I believe, in 1996. We knew that the Bull

8 Trout was going to be petitioned for listing, of course,

9 far in advance of that. In fact, when we began the

10 relicensing effort, we knew the Bull Trout was going to

11 be petitioned for listing.

12 There are not many things that can alter

13 the nature of an original hydropower license, especially

14 one issued in the 1950s, it's virtually immutable, except

15 for compliance with the Endangered Species Act, so we had

16 been in consultation with the U.S. Fish and Wildlife

17 Service, Department of Interior and the Federal Energy

18 Regulatory Commission on the Bull Trout issue in a manner

19 that was concurrent with the settlement process for the

20 Clark Fork.

21 The settlement agreement defines the

22 measures that will mitigate our projects' effects to Bull

23 Trout, providing value for those projects into the future

24 and we would have had to negotiate some kind of an

25 agreement with those parties to protect Bull Trout even

731

CSB REPORTING LaBOLLE (Di)
Wilder, Idaho 83676 Avista

1 if we had not been in a relicensing, and so customers

2 today would be facing conditions flowing from that

3 negotiation whether we had a relicensing case before the

4 Federal Energy Regulatory Commission or not. It's just

5 an additional way in which customers today benefit from

6 the agreement that has been reached even before the time

7 the license is issued.

8 Q Another quick example, please.

9 A I think we talked about it from the

10 resource perspective in response to Mr. Shurtliff's

11 question. I believe the other is that in the Federal

12 Energy Regulatory Commission licensing, it's not about

13 when you get the license, it's about what conditions set

14 up the foundation for a license and the settlement

15 agreement defines what the license will be in all

16 likelihood and really assures that we'll get a license

17 quickly and a license that comports with the settlement

18 itself.

19 Q Okay. Lastly, your attention was directed

20 during cross-examination, I think by Staff, to one

21 element that appears in your Exhibit 25, the

22 administration of programs, the entry of $1.39 million.

23 A Yes.

24 Q Do you recall that?

25 A Yes.

732

CSB REPORTING LaBOLLE (Di)
Wilder, Idaho 83676 Avista

1 Q And that's shown on your Exhibit 25, page 1

2 of 1, it's really the last line item, isn't it?

3 A Yes, it is.

4 Q And there are a number of other items

5 preceding that on that exhibit page, all of which then

6 total to $1,861,000?

7 A Yes.

8 Q And you testified that the -- just as to

9 the one component, but is it your testimony that in

10 combination all of these expenditures are being made

11 during this year and would expect to be made in roughly

12 comparable amounts in ensuing years?

13 A Yes, that is my testimony.

14 MR. MEYER: That's all I have. Thank you.

15 COMMISSIONER SMITH: Thank you.

16 Thank you for your testimony.

17 THE WITNESS: Thank you.

18 (The witness left the stand.)

19 MR. MEYER: The next witness is Tara Knox.

20

21

22

23

24

25

733

CSB REPORTING LaBOLLE (Di)
Wilder, Idaho 83676 Avista

1 TARA L. KNOX,

2 produced as a witness at the instance of Avista

3 Corporation, having been first duly sworn, was examined

4 and testified as follows:

5

6 DIRECT EXAMINATION

7

8 BY MR. MEYER:

9 Q Welcome to the fraternity of first-time

10 witnesses, I guess.

11 A Thank you.

12 Q For the record, please state your name and

13 your employer.

14 A My name is Tara Knox and I'm employed by

15 Avista Corp.

16 Q And have you prepared both direct and

17 rebuttal testimony in this case?

18 A Yes, I have.

19 Q Do you have any changes to make to that?

20 A No, I do not.

21 Q Are you also sponsoring what have been

22 marked as Exhibits 14 through 18?

23 A Yes, I am.

24 Q Any corrections to make to those exhibits?

25 A No.

734

CSB REPORTING KNOX (Di)
Wilder, Idaho 83676 Avista

1 Q So if I were to ask you the questions that

2 appear in your prefiled direct and rebuttal, would your

3 answers be the same?

4 A Yes, they would.

5 MR. MEYER: With that, I ask that

6 Ms. Knox's testimony, both direct and rebuttal, be

7 entered as if read and move for the admission of

8 Exhibits 14 through 18.

9 COMMISSIONER SMITH: If there is no

10 objection, it is so ordered.

11 MR. MEYER: Thank you.

12 (Avista Corporation Exhibit Nos. 14-18

13 were admitted into evidence.)

14 (The following prefiled direct and

15 rebuttal testimony of Ms. Tara Knox is spread upon the

16 record.)

17

18

19

20

21

22

23

24

25

735

CSB REPORTING KNOX (Di)
Wilder, Idaho 83676 Avista

1 Q. Would you please state your name,

2 business address and present position with the Washington

3 Water Power Company?

4 A. My name is Tara L. Knox. My business

5 address is East 1411 Mission Avenue, Spokane, Washington.

6 I am employed as a Rate Analyst in the Rates and Tariff

7 Administration department.

8 Q. Would you briefly describe your duties?

9 A. I am responsible for preparing data for and

10 maintaining the regulatory cost of service model for the

11 Company as well as providing support in the preparation

12 of Commission Basis results of operations and

13 miscellaneous other duties as required.

14 Q. Would you briefly describe your educational

15 background?

16 A. I graduated from Washington State

17 University with a Bachelor of Arts degree in General

18 Humanities in 1982 and a Master of Accounting degree in

19 1990. As an employee in the rate department of

20 Washington Water Power since 1991 I have attended several

21 ratemaking classes including the EEI Electric Rates

22 Advanced Course which specializes in cost allocation and

23 cost of service issues.

24 Q. What is the scope of your testimony in this

25 proceeding?

736

Knox, Di 1
WWP

1 A. My testimony and exhibits will cover the

2 Company's cost of service study performed for this

3 proceeding.

4 Q. Would you please briefly summarize your

5 testimony?

6 A. The Company believes the base case cost of

7 service study presented in this case includes the most

8 accurate representation of the costs to serve each

9 customer group. I have also provided the results of

10 alternative scenarios to show the potential impact of

11 different key allocation decisions in the cost of service

12 process.

13

14 /

15

16 /

17

18 /

19

20

21

22

23

24

25

737

Knox, Di 1A
WWP

1 The study shows residential and extra large

2 general service rate schedules earning substantially less

3 than the overall return. The small general service

4 Schedule 11 earns substantially more than the requested

5 return. Large general service Schedule 21 and pumping

6 service Schedule 31 show returns above the overall

7 return, but within a reasonable proximity to the

8 requested return. Street and area lights are earning

9 near the overall return.

10 I also address unbundled costs by showing the

11 component costs within the current rates, the component

12 costs at the proposed revenues, and the full component

13 costs if each customer group were providing the requested

14 rate of return.

15 Q. Are you sponsoring any exhibits to be

16 introduced in this proceeding?

17 A. Yes. I am sponsoring the following

18 exhibits:

19 Exhibit No. 14, a flow chart illustrating the cost

20 of service study process;

21 Exhibit No. 15, the complete output of the cost of

22 service model showing the test

23 year results of operations at

24 present rates;

25 Exhibit No. 16, a methodology matrix showing the

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1 functionalization, classification

2 and allocation selections used in

3 the study presented as Exhibit

4 No. 15;

5 Exhibit No. 17, summary results from the base case

6 plus four alternate scenarios; and

7 Exhibit No. 18, unbundled functional cost

8 comparison for present, proposed,

9 and full cost.

10 Q. Were these exhibits prepared by you or

11 under your supervision?

12 A. Yes, they were.

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23

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1 Q. What is a cost of service study and what is

2 its purpose?

3 A. A cost of service study is an

4 engineering-economic study which apportions the revenue,

5 expenses, and rate base associated with providing

6 electric service to designated groups of customers. It

7 indicates whether the revenue provided by the customers

8 recovers the cost to serve those customers. The study

9 results are used as a guide in determining the

10 appropriate rate spread among the groups of customers.

11 Q. Please briefly describe the process used in

12 developing a cost of service study?

13 A. There are three basic steps involved in a

14 cost of service study: functionalization, classification,

15 and allocation. I have included a flow chart

16 illustrating the process as Exhibit No. 14.

17 First, the expenses and rate base associated with

18 the electric system under study are assigned to

19 functional categories. The uniform system of accounts

20 provides the basic segregation into production,

21 transmission, and distribution. Traditionally customer

22 accounting, customer information, and sales expenses are

23 included in the distribution function and administrative

24 and general expenses and general plant rate base are

25 allocated to all functions.

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1 Second, the expenses and rate base items which

2 cannot be directly assigned to customer groups are

3 classified into three primary cost components: energy,

4 demand or customer related. Energy related costs are

5 allocated based on each rate schedule's share of

6 commodity consumption. Demand (capacity) related costs

7 are allocated to rate schedules on the basis of each

8 schedules contribution to peak demand. Customer related

9 items are allocated to rate schedules based on the number

10 of customers within each schedule. The number of

11 customers may be weighted by appropriate factors such as

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20

21

22

23

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1 relative cost of metering equipment. In addition to

2 these three cost components, any revenue related expense

3 is allocated based on the proportion of revenues by rate

4 schedule.

5 The final step is allocation of the costs to the

6 various rate schedules utilizing the allocation factors

7 selected for each specific cost item. These factors are

8 derived from usage and customer information associated

9 with the test period results of operations.

10 BASE CASE COST OF SERVICE

11 Q. What are the results of the Company's base

12 case cost of service study?

13 A. The following table shows the rate of

14 return and the ratio of the schedule return to the

15 overall return (relative return ratio) at present rates

16 for each rate schedule:

17 Customer Class Rate of Return Return Ratio

18 Residential Service
Schedule 1 3.94% 0.57
19 Small General Service
Schedule 11 13.08% 1.89
20 Large General Service
Schedule 21 10.06% 1.45
21 Extra Large General
Service Schedule 25 4.47% 0.64
22 Pumping Service
schedule 31 10.64% 1.53
23 Lighting Schedules
41-49 7.54% 1.09
24
Total Idaho Electric 6.94% 1.00
25

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1 As can be observed from the above table,

2 residential and extra large general service schedules (1

3 and 25) show under-recovery of the cost to serve them.

4 The summary results of this study were provided to

5 witness Hirschkorn as an input into development of the

6 proposed rates.

7 Q. What is the basis for the cost of service

8 study you have provided as Exhibit No. 15?

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1 A. The cost of service study provided by the

2 Company as Exhibit No. 15 is based on the 1997 test year

3 pro forma results of operations presented by witness

4 Falkner in Exhibit No. 11. Exhibit No. 15 will be

5 discussed in more detail later in my testimony.

6 Q. Does the Company's base case cost of

7 service study follow the methodology filed in the

8 Company's last general rate case in Idaho?

9 A. The basic methodology is the same as the

10 cost of service study filed in Case No. U-1008-256, with

11 two exceptions.

12 Q. Please explain these two differences.

13 A. First, distribution costs are classified to

14 customer and demand by the basic customer method in the

15 current case whereas in 1986 the minimum distribution

16 system method was used. Second, administrative and

17 general costs are directly assigned to functions where

18 possible and the remaining general costs are included

19 with the distribution function and classified 40% to

20 energy and 60% to customer. In the 1986 case most

21 administrative and general costs were allocated by the

22 sum of other operating expenses or plant which implies a

23 functional allocation based on the components of the

24 sums.

25 Q. Please explain the Basic Customer

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1 classification methodology applied to Distribution

2 facilities related costs in this study.

3 A. The Basic Customer method considers only

4 services and meters (FERC Accounts 369 and 370

5 respectively) to be customer related distribution plant.

6 All other distribution plant is then considered demand

7 related. This division delineates plant which benefits

8 an individual customer from plant which is part of the

9 system.

10 Q. Why do you use the basic customer method to

11 classify distribution costs?

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1 A. The basic customer method provides a

2 reasonable, clearly definable division between plant that

3 provides service only to individual customers from plant

4 that is part of the interconnected distribution network.

5 Additionally, the basic customer method has been

6 explicitly accepted for both electric and gas cost of

7 service in the State of Washington, whereas the minimum

8 distribution system method has been consistently rejected

9 there. Consequently, I decided not to perform an updated

10 minimum distribution system study since it could not be

11 used for both jurisdictions and the basic customer method

12 is theoretically sound and has already been adopted in

13 the Washington jurisdiction.

14 Q. Why have you changed the methodology

15 related to administrative and general costs?

16 A. One of the issues that became apparent

17 through the Unbundled Cost Studies performed in response

18 to GNR-E-97-1 was the inadequacy of the "Other O&M" based

19 allocation methodology to address the functional

20 association appropriate for administrative and general

21 costs. Under that methodology over 54% of administrative

22 and general costs were allocated to the Production

23 function which we consider an unreasonably large

24 proportion.

25 Q. How does the method for dealing with

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1 administrative and general costs presented in the current

2 study address this problem?

3 A. The method I have applied in this study

4 first directly assigns administrative and general costs

5 which have a direct association to the production,

6 transmission, distribution, and customer relations

7 functional units within the Company. These amounts are

8 then allocated to customer groups using the proportions

9 of related plant in service assigned and allocated to the

10 customer groups (except customer relations

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18

19

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22

23

24

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1 which uses number of customers). The effect of using

2 plant to allocate functionalized administrative and

3 general costs gives recognition to the energy, demand,

4 and customer allocations applied to plant in service.

5 The remainder of administrative and general costs

6 support overall utility needs such as accounting, human

7 resources, telecommunications, etcetera which are

8 necessary to the business but not directly associated

9 with specific functions. These costs have been put in

10 the category of Other and are considered separately.

11 Just as these costs have no direct relationship to

12 operating functions, neither do they have a direct

13 relationship to customer groups. Careful consideration

14 was given to develop what I believe is an appropriate

15 "corporate" allocator for this category of costs which

16 uses a combination of consumption and customer

17 allocations.

18 Q. Please summarize the methodology applied to

19 the base case study?

20 A. Exhibit No. 16 provides a methodology

21 matrix summarizing the functionalization, classification

22 and allocation choices implemented in this study. This

23 study could be referred to as a Peak Credit, Basic

24 Customer methodology with segregated A&G.

25 Q. Please explain the Peak Credit

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1 classification methodology applied to production and

2 transmission costs in this study.

3 A. The Peak Credit methodology acknowledges

4 that baseload production facilities provide energy

5 throughout the year as well as capacity during system

6 peaks and likewise the transmission system is built not

7 only for peak use but everyday delivery of energy. The

8 demand/energy ratio is determined by the relationship of

9 the current replacement cost per kW generating capacity

10 of a peaking unit (simple cycle combustion turbine) to

11 the current replacement cost per kW generating capacity

12 of the Company's

13

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19

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21

22

23

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1 thermal or hydro plant. The 1997 peak credit ratio for

2 thermal plant is 28.45% to demand and 71.55% to energy.

3 The 1997 peak credit ratio for hydro plant is 29.20% to

4 demand and 70.80% to energy. Transmission costs are

5 classified by a fifty-fifty weighting of the thermal and

6 hydro peak credit ratios resulting in the transmission

7 peak credit ratio of 28.82% to demand and 71.18% to

8 energy. Fuel and load dispatching expenses are

9 classified entirely to energy. Peaking plant related

10 costs are classified entirely to demand. Purchased Power

11 and Other Power Supply expenses are classified to demand

12 and energy by the relative amounts of assigned and

13 allocated Production Plant in Service.

14 Q. How are distribution facilities and related

15 costs classified in this study?

16 A. As discussed previously, applying the basic

17 customer method for distribution plant and related

18 operating and maintenance expenses, all distribution

19 costs are considered demand related except for meters,

20 services and the direct assignment of street light and

21 signal systems which are classified as customer related.

22 Q. How are customer service, customer

23 information, and sales expenses treated in this study?

24 A. These costs are the core of the customer

25 relations functional unit which is included with the

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1 distribution cost category. For the most part they are

2 classified as customer related. Exceptions are

3 demonstrating and selling expenses which are classified

4 as energy related and uncollectible accounts expense

5 which is considered separately as a revenue conversion

6 item. Demand Side Management expenses recorded in

7 Account 908 are also considered separately from the other

8 customer information costs.

9 Q. Would you please discuss the treatment of

10 demand side management in this study?

11

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19

20

21

22

23

24

25

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WWP

1 A. The Company's tariff rider, as discussed in

2 witness Falkner's testimony, began in March 1995. The

3 associated filing provided for accelerated amortization

4 of the deferred balance at December 1994 beginning

5 January 1995. The purpose of demand side management

6 programs discussed in that proceeding was fourfold:

7 (1) supply considerations, (2) a service to customers,

8 (3) a conduit to achieve public policy, and (4) the

9 Company's social responsibility to contribute to the

10 conservation of natural resources. Given the purpose of

11 the investment, I chose to include both the investment

12 and amortization expense as a separate item in the

13 distribution cost category. These costs were classified

14 implicitly to demand and energy by the sum of production

15 plant in service, then allocated to rate schedules by

16 coincident peak demand and consumption respectively. The

17 Schedule 91 Tariff Rider Revenue is applied in the same

18 manner as other operating revenues as a reduction to

19 cost. The offsetting expense recorded in account 908 is

20 allocated to customers by the tariff rider revenue amount

21 collected from each customer group effectively

22 eliminating both the revenue and the expense. The

23 summary results shown on Exhibit No. 15 Part 3 page 3,

24 line 178 shows the 1997 Schedule 91 revenue by customer

25 group. Witness Falkner is presenting the

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1 cost-effectiveness analysis related to these costs.

2 Q. How are revenue related items treated in

3 this study?

4 A. In this study uncollectibles and commission

5 fees have been classified as revenue related and are

6 allocated by pro forma revenue. These items vary with

7 revenue and are included in the calculation of the

8 revenue conversion factor. Income tax expense items are

9 allocated to schedules by net income adjusted by interest

10 expense. These items are then assigned to component cost

11 categories for the functional summaries. The revenue

12 conversion items have been reduced to a percent of all

13 other costs and applied to each

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22

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1 cost category by that ratio. Similarly, income tax items

2 have been reduced to a percent of net income before tax

3 then assigned to cost categories by relative rate base

4 (as is net income).

5 Q. How are Other costs classified and

6 allocated in this study?

7 A. As mentioned previously administrative and

8 general costs which could not be directly associated with

9 production, transmission, distribution, or customer

10 relations functions were placed in the category of Other.

11 A single allocation factor is applied to all of the

12 amounts categorized as Other which is made up of a 40%

13 weighting of annual kWh sales (energy classification) and

14 a 60% weighting of average number of customers (customer

15 classification). This factor was arrived at intuitively

16 from a sense that most general costs, while not directly

17 related to individual customers, are impacted by the

18 number of transactions generated, which in turn is

19 related to the number of customers served by the utility.

20 For example, when there are more customers, there are

21 more bills being processed, which cause more accounting

22 transactions to be dealt with in the computer databases,

23 where the size of individual transactions are irrelevant.

24 However, some general costs will be impacted by the size

25 of a customer, for example, budgeting and forecast will

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1 make an estimate regarding the usage of thousands of

2 small customers, but will spend considerable effort to

3 project the usage of individual large customers simply

4 because the impact on the utility of those individual

5 customers is greater than the impact of individual small

6 customers. The consumption allocator acknowledges the

7 relative resources applied to customer groups for some

8 aspects of general costs. The 60% customer, 40% energy

9 weighting represents an estimate of how much of these

10 general costs are of the first type compared to the

11 second.

12

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1 Q. Have you done any analysis looking at other

2 customer/energy weightings?

3 A. Yes. I performed two alternative scenarios

4 testing the impact of changing the weights in the

5 customer/energy relationship. These scenarios are

6 discussed in detail later in my testimony.

7 Q. How are demand related costs assigned to

8 customer groups?

9 A. Production and transmission demand related

10 costs are allocated to the customer classes by class

11 contribution to the average of the twelve monthly system

12 coincident peak loads. Although the Company is

13 technically a winter peaking utility, it experiences high

14 summer peaks and careful management of capacity

15 requirements is required throughout the year. The use of

16 the average of twelve monthly peaks recognizes that

17 customer capacity needs are not limited to the heating

18 season.

19 Distribution demand related costs which cannot be

20 directly assigned are allocated to customer class by the

21 average of the twelve monthly non-coincident peaks for

22 each class. Distribution facilities that serve only

23 secondary voltage customers are allocated by the

24 non-coincident peak excluding primary voltage customers.

25 This includes line transformers, services, and secondary

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1 voltage overhead or underground conductors and devices.

2 Q. How are energy related costs assigned to

3 customer groups?

4 A. Energy related costs are allocated to class

5 by pro forma annual kilowatthour sales adjusted for

6 losses to reflect generation level consumption.

7 Q. How are customer related costs assigned to

8 customer groups?

9 A. Most customer costs are allocated by

10 average number of customers. Weighted customer

11 allocators have been developed using typical current cost

12 of meters, estimated meter reading time, and direct

13 assignment of billing costs for hand-billed

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1 customers. Street and area light customers are excluded

2 from metering and meter reading expenses as their service

3 is not metered.

4 Q. Please describe what is shown in Exhibit

5 No. 15?

6 A. The printouts from the Excel spreadsheet

7 model used to calculate the cost of service are presented

8 in their entirety as Exhibit No. 15. This detail has

9 been divided into three distinct segments.

10 Part 1 is the spreadsheet called "Proforma". The

11 accounting data to be used in the study is entered here.

12 Part 2 is the cost of service calculation from the

13 spreadsheet called "Assign" showing the

14 functionalization, classification, and allocation of each

15 line item developed in "Proforma". The supporting

16 schedules required to run the model made up of the

17 allocation and classification factors used in the study

18 are shown on pages 31 through 36.

19 Finally, Part 3 is the spreadsheet called

20 "Sumcost". It consists of four summaries created from

21 the information calculated in Part 2 and the supporting

22 schedules used to create them. The first summary

23 labelled "Cost of Service Basic Summary" shows the

24 results of the study by FERC account category with the

25 rate of return by rate schedule and the ratio of each

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1 schedules return to the overall return shown on Lines 58

2 and 59. The second summary labelled "Unbundled Cost

3 Component Summary" shows the results of the study grouped

4 into production, transmission, and distribution cost

5 categories computed at present revenue, proposed revenue,

6 and requested return applied uniformly to all customer

7 groups. The third summary labelled "Functional Cost

8 Summary" shows the items which make up the production,

9 transmission, and distribution cost categories. The

10 fourth summary labelled "Functional Cost Summary by

11 Classification" shows the classification of costs within

12 the production, transmission, and distribution cost

13

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1 categories. Following this summary are supporting

2 schedules which show the derivation of the items included

3 in each of the cost categories.

4 ALTERNATIVE SCENARIO NO. 1

5 Q. Were the results of the base case

6 methodology compared to the methodology from Case

7 No. U-1008-256?

8 A. Yes, alternative scenario No. 1 shown in

9 Exhibit No. 17 represents the results using the

10 methodology applied in Case No. U-1008-256. The minimum

11 distribution system customer classifications were

12 estimated using the relationship of customer related

13 plant to total plant by account in the 1986 case applied

14 to 1997 plant balances. Most administrative and general

15 expenses are allocated by the sum of other operating and

16 maintenance expenses excluding purchased power and fuel

17 accounts. General plant and plant related general

18 operating expenses are allocated by the total of

19 production, transmission, and distribution plant. As you

20 can see by the relative return ratios shown in the table

21 below the results are similar with some tradeoff between

22 extra large general service and residential service and a

23 profound improvement for street and area lights.

24

25

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1 Customer Group Base Case U-1008-256 Difference

2 Residential .57 .65 +.08

3 Small General 1.89 1.94 +.05

4 Large General 1.45 1.38 -.07

5 Extra Large General .64 .52 -.12

6 Pumping 1.53 1.58 +.05

7 Lighting 1.09 .81 -.28

8

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1 The increase in customer classification for

2 distribution plant is largely offset by the decreased

3 customer based allocation inherent in the A&G allocator

4 providing similar results.

5 ALTERNATIVE SCENARIO NO. 2

6 Q. Was the Peak Credit assumption compared to

7 other Production and Transmission theories?

8 A. Yes. The Peak Credit method heavily

9 weights the energy classification. An alternative

10 production/transmission theory which emphasizes demand

11 classification was performed to provide a basis for

12 comparison. I selected the straight fixed-variable

13 approach which assumes all fixed costs are demand related

14 and variable costs are energy related. The changes from

15 base case are limited to production and transmission

16 costs. All plant and plant related operating and

17 maintenance expenses are considered fixed and classified

18 as demand related. Purchased Power, Fuel, and Wheeling

19 expenses are considered variable and classified as energy

20 related. The results of this study are summarized under

21 alternative scenario No. 2 on Exhibit No. 17. The table

22 below compares the relative return ratios of the base

23 case peak credit to straight fixed variable production

24 and transmission cost classification theories.

25

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1 Customer Group Base Case SFV Difference

2 Residential .57 .49 -.08

3 Small General 1.89 1.87 -.02

4 Large General 1.45 1.45 .00

5 Extra Large General .64 .82 +.18

6 Pumping 1.53 1.89 +.36

7

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1 Lighting 1.09 1.24 +.15

2 The demand heavy allocations favor large

3 industrial customers with good load factors, seasonal

4 irrigation and dusk to dawn lighting customers with

5 limited contribution to coincident peaks, and are

6 punitive to low load factor residential customers.

7 However, note that Residential and Extra Large General

8 service customers are once again below the overall return

9 while the other schedules earn more than the overall

10 return.

11 ALTERNATIVE SCENARIOS NO. 3 AND NO. 4

12 Q. Were results using alternative customer and

13 energy weights for the Other cost category compared

14 against the base case?

15 A. Yes. In an attempt to show the potential

16 impact of modifying the weights applied to customer and

17 energy portions of the allocator used for the "Corporate

18 Cost Allocator" in the base case study the two extreme

19 cases were prepared. Exhibit No. 17 alternative

20 scenarios No. 3 and No. 4 represent the results of this

21 study keeping everything the same as the base case except

22 for the customer/energy weights applied to general costs.

23 Alternative No. 3 shows the extreme weighting 100%

24 customer and Alternative No. 4 the opposite with 100%

25 energy. The table below shows a comparison of the

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1 relative return ratios for the Base Case and the two

2 extreme cases.

3 Base Cust-Base Energy-Base
Customer Group Case Customer Energy Difference Difference
4

5 Residential .57 .44 .76 -.13 +.19

6 Small General 1.89 1.80 2.02 -.09 +.13

7 Large General 1.45 1.61 1.22 +.16 -.23

8 Extra Large
General .64 .84 .36 +.20 -.28
9

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1 Pumping 1.53 1.64 1.37 +.11 -.16

2 Lighting 1.09 1.13 1.03 +.04 -.06

3 Consistently, even under these extreme cases

4 residential and extra large general service customers

5 show under-recovery of the costs to serve them while the

6 other schedules show relative over-recovery compared to

7 the present overall return.

8 Q. Please provide a summary table comparing

9 all the alternative cost study results prepared for this

10 case.

11 A. The following table compares the relative

12 rate of return ratios produced by each alternative

13 costing methodology prepared for this case and shown in

14 the result summary provided as Exhibit No. 17.

15 Customer Group Base Case U-1008-256 SFV Customer Energy

16 Residential .57 .65 .49 .44 .76

17 Small General 1.89 1.94 1.87 1.80 2.02

18 Large General 1.45 1.38 1.45 1.61 1.22

19 Extra Large
General .64 .52 .82 .84 .36
20
Pumping 1.53 1.58 1.89 1.64 1.37
21
Lighting 1.09 .81 1.24 1.13 1.03
22

23 Consistently, no matter which variation you look

24 at, residential (Schedule 1) and extra large general

25 service (Schedule 25) customers are providing less than

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1 the cost to serve them. The base case methodology

2 produces conservative results in the sense that the cost

3 relationships fall in the middle of the range produced by

4 the alternative methodologies.

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1 UNBUNDLED COST ANALYSIS

2 Q. How was the issue of unbundled costs

3 addressed in this study?

4 A. The functionalization process which is the

5 first step in a cost of service study provides the

6 framework for analysis of unbundled revenue

7 responsibility. The study examines rate base and

8 expenses from which it determines rate of return by

9 customer group given revenues from existing rates. The

10 component costs in the study can be summarized into

11 desired unbundled cost categories with the return

12 component (net income by customer group) assigned by

13 relative rate base for each component. The result of

14 this analysis, presented on lines 1 through 8 of Exhibit

15 No. 18, represents the unbundled cost components of

16 current rates. This is different from the concept of

17 unbundled cost as it was measured in Case No. GNR-E-97-1.

18 Q. How were unbundled costs defined in Case

19 No. GNR-E-97-1?

20 A. The overall return for the Idaho

21 Jurisdiction was applied uniformly to all cost components

22 for all customer groups based on relative rate base to

23 represent the full embedded cost of service for each

24 component. Revenue and income related expenses, namely

25 uncollectibles, commission fees, and income taxes were

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1 assigned to customer groups as if each group were

2 contributing precisely the revenue required to produce

3 the overall return.

4 Q. Have you computed the full component cost

5 as interpreted in the Unbundling Studies?

6 A. Yes. I applied the requested rate of

7 return uniformly to the rate base components from the

8 base case and adjusted revenue related expenses and

9 income tax to match the requested revenue requirement in

10 this case. These adjusted amounts were added to the

11 expenses from the base case to represent the full

12 embedded cost of service

13

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21

22

23

24

25

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1 for each cost component. The results are shown on lines

2 17 through 24 of Exhibit No. 18. For comparison purposes

3 I also computed the component costs assuming revenues

4 from the proposed rate design. These results are shown

5 on lines 9 through 16 of Exhibit No. 18.

6 Q. What costs are included in the production

7 category?

8 A. The following costs have been included in

9 the production category:

10 * Production related Operating and

11 Maintenance Expenses

12 * Administrative and General Expenses

13 assigned to Production

14 * Depreciation and Amortization Expenses

15 associated with Production Rate Base

16 * WNP-3 Settlement Exchange Power cost

17 * Property taxes associated with Production

18 Plant and kWh Generation taxes

19 * Proportionate share of Income Taxes

20 * Proportionate share of Uncollectibles and

21 Commission Fees

22 * Return on Production Rate Base

23 * Reduced by Other Operating Revenues

24 associated with Production or Power Supply.

25 Q. What costs are included in the transmission

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1 category?

2 A. The following costs have been included in

3 the transmission category:

4 * Transmission related Operating and

5 Maintenance Expenses

6 * Administrative and General Expenses

7 assigned to Transmission

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16

17

18

19

20

21

22

23

24

25

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Knox, Di 18A
WWP

1 * Depreciation and Amortization Expenses

2 associated with Transmission Rate Base

3 * Property taxes associated with Transmission

4 Plant

5 * Proportionate share of Income Taxes

6 * Proportionate share of Uncollectibles and

7 Commission Fees

8 * Return on Transmission Rate Base

9 * Reduced by Other Operating Revenues

10 associated with Transmission.

11 Q. What costs are included in the distribution

12 category?

13 A. The following costs have been included in

14 the distribution category:

15 * Distribution related Operating and

16 Maintenance Expenses

17 * Customer Relations related Operating

18 Expenses

19 * Administrative and General Expenses

20 assigned to Distribution, Customer

21 Relations, and Other

22 * Demand Side Management expenses

23 * Depreciation and Amortization Expenses

24 associated with Distribution and General

25 Rate Base

772

Knox, Di 19
WWP

1 * Property taxes associated with Distribution

2 or General Plant and miscellaneous

3 Distribution taxes

4 * Proportionate share of Income Taxes

5 * Proportionate share of Uncollectibles and

6 Commission Fees

7 * Return on Distribution Rate Base

8 * Return on Demand Side Management Rate Base

9

10

11 /

12

13 /

14

15 /

16

17

18

19

20

21

22

23

24

25

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Knox, Di 19A
WWP

1 * Reduced by Other Operating Revenues

2 associated with Distribution or Demand Side

3 Management.

4 Q. What is the significance of the unbundled

5 cost analysis?

6 A. In the past several years the Company has

7 embarked on several experiments involving the segregation

8 of the provision of power from the delivery of it, namely

9 Direct Access Delivery Service, and More Options for

10 Power Service I and II. Component cost analysis provides

11 a beginning point for determining the appropriate amounts

12 to apply toward the segregated parts. Further,

13 comparison of the component costs reflected in the

14 proposed rate design to the same component costs at

15 uniform return provides perspective on the difference

16 between rates and cost. This analysis, on an unbundled

17 basis, also illustrates the movement toward more

18 accurately reflecting the cost for residential and extra

19 large general service customers proposed in this case.

20 Q. Does this conclude your direct testimony?

21 A. Yes, it does.

22

23

24

25

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Knox, Di 20
WWP

1 Q Would you please state your name, business

2 address and present position with Avista Corporation?

3 A My name is Tara L. Knox. My business

4 address is East 1411 Mission Avenue, Spokane, Washington.

5 I am employed as a Rate Analyst in the Rates and

6 Regulation department.

7 Q Have you previously submitted direct

8 testimony in this proceeding?

9 A Yes, I sponsored the cost of service study

10 in this case.

11 Q What is the scope of your rebuttal

12 testimony in this proceeding?

13 A My testimony responds to the testimony of

14 Mr. Dennis E. Peseau appearing on behalf of the Potlatch

15 Corporation. Particularly, I will address Mr. Peseau's

16 testimony regarding cost of service methodology.

17 Q. Please summarize your rebuttal testimony.

18 A. Mr. Peseau recommends five changes to the

19 cost of service methodology designed to shift costs away

20 from his client customer group and incidentally onto

21 residential customers, doing so without any real support

22 or justification. Mr. Peseau fails to acknowledge in his

23 testimony that the Company study includes only two

24 departures from prior accepted methodology with a net

25 effect that is actually favorable to his client.

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Knox, Di-Reb 1
Avista

1 Additionally, in his rationale for his proposed changes,

2 Mr. Peseau makes untrue assertions regarding what this

3 Commission has found acceptable for other Idaho

4 utilities.

5 Q. Has the Commission Staff reviewed the

6 Company cost of service study presented in this case?

7 A. Yes, Staff witness Hessing has examined the

8 Company cost of service study and associated workpapers.

9 Beginning at the bottom of page 4 of his direct

10

11 /

12

13 /

14

15 /

16

17

18

19

20

21

22

23

24

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Knox, Di-Reb 1A
Avista

1 testimony Mr. Hessing states, "I am willing to accept the

2 methodology changes that the Company proposes in this

3 case based on the justification provided by the Company."

4 Q. How does the Company cost of service study

5 in this case compare to the methodology filed for the

6 Idaho Unbundling Study Case No. GNR-E-97-1/WWP-E-98-1?

7 A. The methodology applied in the cost study

8 for this case differs from the Idaho Unbundling Study

9 methodology by the treatment of administrative and

10 general costs and some refinements to the

11 primary/secondary categorization of distribution plant.

12 Potlatch had the opportunity through Case No. WWP-E-98-1,

13 but refrained from filing testimony on any of the items

14 Mr. Peseau finds so "contrary to Avista's filings before

15 FERC and previous Idaho Commission filings" (Peseau Di

16 page 32, line 1).

17 Q. Mr. Peseau recommends the minimum

18 distribution system method for classification of

19 distribution costs. What is your response?

20 A. On page 34 of his testimony Mr. Peseau

21 describes the demand relationship inherent in planning

22 and building of electrical distribution systems. His

23 customer design demand argument supports the basic

24 customer methodology, which assigns the portions of the

25 networked system that cannot be directly assigned by the

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Knox, Di-Reb 2
Avista

1 relative demand of the customer groups. Ideally, the

2 networked distribution plant would be assigned by the sum

3 of each customers exact design considerations. However,

4 this information is not available, so a surrogate is

5 developed to estimate the design demand characteristics

6 of the customer mix for each group of customers, namely,

7 the non-coincident peak demand segregated by voltage

8 level included in my Exhibit 15.

9 Q. Mr. Peseau implies that the minimum

10 distribution system is the only distribution cost

11 classification methodology accepted by the Idaho

12 Commission, is this true?

13

14 /

15

16 /

17

18 /

19

20

21

22

23

24

25

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Knox, Di-Reb 2A
Avista

1 A. No. Pacificorp's Utah Power and Light

2 Idaho jurisdiction utilizes essentially the same

3 classification methodology I have employed in this study

4 which was accepted by this Commission.

5 Q. Mr. Peseau objects to the use of twelve

6 monthly average peak demand allocators. How do you

7 respond to this?

8 A. Single peak allocators will assign more

9 costs to residential customers, and less to large

10 industrial customers than the averaged peaks included in

11 my study. The averaged peaks have traditionally been

12 used in Avista Utilities (then called Washington Water

13 Power) cost studies in the Idaho jurisdiction. Both

14 Idaho Power and Utah Power and Light studies also

15 utilized twelve monthly averages for their coincident

16 peak allocators.

17 Three factors make the monthly averages more

18 reasonable than single peak allocators do. First, single

19 peak allocators are subject to weather-related

20 variability which can result in significant differences

21 from year to year. The use of the average of the twelve

22 monthly peaks tends to have a normalizing effect on the

23 demand allocator. Second, capacity concerns are

24 important throughout the year, not just at a single peak.

25 Avista experiences significant air conditioning load in

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Knox, Di-Reb 3
Avista

1 late summer when supply is scarce and the cost high due

2 to low stream flows at that time of year. A single peak

3 allocator does not recognize the cost responsibility in

4 any other months. Idaho Power's use of twelve monthly

5 peaks weighted by the marginal cost of capacity for the

6 different months emphasizes the need for multiple peak

7 allocators to capture the fact that capacity is a cost

8 that varies throughout the year. Finally, monthly peak

9 allocators approximate demand billing determinants

10 thereby capturing the annual contribution when measured

11 by kW month.

12

13

14 /

15

16 /

17

18 /

19

20

21

22

23

24

25

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Knox, Di-Reb 3A
Avista

1 Q. Avista classifies transmission costs by

2 50/50 weighting of the peak credit ratios for hydro and

3 thermal production costs. Mr. Peseau recommends

4 classifying transmission costs entirely as demand

5 related, asserting that Idaho Power classifies

6 transmission 100% to demand, is this true?

7 A. No. Idaho Power separates the transmission

8 system into two segments; power supply related

9 transmission and other transmission. The power supply

10 related transmission is allocated by the system load

11 factor, 68% energy - 32% demand in their last case.

12 Examination of the functionalization summary exhibit from

13 Idaho Power's Case No. IPC-E-94-5 shows that more than

14 75% of their transmission rate base was in the power

15 supply category. The remaining 25% of their transmission

16 costs are allocated by demand. Utah Power and Light,

17 similar to Avista's traditional methodology, treats all

18 of the transmission system in the same manner as

19 generation.

20 Q. Mr. Peseau also makes statements about

21 Avista's FERC transmission rates. Would you please

22 comment?

23 A. Yes. At page 39 beginning at line 5

24 Mr. Peseau states that Avista classifies transmission

25 costs 100% to demand before the FERC. This is untrue,

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Knox, Di-Reb 4
Avista

1 the FERC transmission cost methodology addresses only

2 functionalization, making no classification nor

3 allocation assumptions. Transmission costs before FERC

4 are simply that, total system transmission costs.

5 Q. How does Avista determine its transmission

6 rates under the FERC calculation?

7 A. Avista's network and point-to-point

8 transmission service rates are calculated by dividing the

9 annual transmission related revenue requirement by the

10 average of the 12 monthly transmission contract demands.

11 The monthly transmission contract

12

13 /

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15 /

16

17 /

18

19

20

21

22

23

24

25

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Knox, Di-Reb 4A
Avista

1 demands consist of the Company's net system peak load

2 adjusted for losses plus the contracts to other companies

3 for firm transmission service.

4 As you can see, Mr. Peseau's arguments about

5 aligning retail transmission allocations with FERC

6 wheeling billing determinants are in direct opposition to

7 his recommendation for single peak measurement of

8 coincident peak demand.

9 Q. On page 40 Mr. Peseau implies that a

10 subsidy occurs if retail transmission cost utilizes a

11 classification and allocation methodology that differs

12 from FERC transmission rate design. How do you respond?

13 A. The revenue from FERC transmission

14 transactions is applied as a credit to retail

15 transmission costs distributed to customer groups

16 consistently with those costs rendering the FERC rate

17 design irrelevant to retail cost allocation. State

18 Commissions have jurisdiction over retail issues, and

19 this Commission has seen fit to accept transmission costs

20 treated in the same manner as the generation system for

21 Avista and we see no reason to propose changes at this

22 time.

23 Q. On page 41 of his testimony, Mr. Peseau

24 presents amounts associated with demand side management

25 expenditures, are these numbers misleading with respect

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Knox, Di-Reb 5
Avista

1 to the cost of service study?

2 A. Yes, Mr. Peseau is mixing apples with

3 oranges as it were. The numbers he refers to are related

4 entirely to the post 1995 tariff rider program

5 expenditures. The demand side management costs included

6 in the Company cost of service study explicitly excludes

7 the tariff rider revenue and offsetting expense as we are

8 not proposing adjustments to Schedule 91 in this case.

9 All DSM numbers that remain in the cost of service study,

10 (once the tariff rider revenue is offset by the tariff

11 rider program expense), are derived from the amortization

12 and return on rate base of pre-1995 programs. These

13

14 /

15

16 /

17

18 /

19

20

21

22

23

24

25

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Knox, Di-Reb 5A
Avista

1 programs were planned and implemented for the purpose of

2 delaying the need for generation resources and,

3 therefore, are properly allocated to customer groups by

4 production plant in service.

5 Q. What is your view of Mr. Peseau's suggested

6 changes to the cost of service methodology presented in

7 this case?

8 A. Mr. Peseau refers to cost of service

9 studies in general as being a combination of art and

10 science. Mr. Peseau has selectively applied a

11 combination of alternative theories each designed to

12 shift costs away from his client customer group and onto

13 residential customers. While recommending a return to

14 the minimum size distribution system theory utilized in

15 the Company's last general rate proceeding, Mr. Peseau

16 has neglected to mention that the other change from the

17 old method, namely the new common cost allocator, is very

18 favorable to large industrial customers. The other

19 alternatives he presents would move even further away

20 from the previously accepted methodology upon which

21 current rates are based.

22 Q. Is continuity with previous methodology

23 important?

24 A. As Mr. Peseau's Exhibit 209 shows,

25 methodology changes can have profound impacts on cost

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Knox, Di-Reb 6
Avista

1 responsibility of a given customer group especially when

2 you combine many changes favorable to that group. As we

3 move toward a rate design reflective of the perceived

4 costs to provide service to customers, it is important to

5 consider consistency over time in the applied

6 methodology. Holding methodology constant, costs per

7 unit will change over time due to changes in usage

8 characteristics of the customer groups and the functional

9 makeup of costs at the jurisdictional level. When you

10 add changes in methodology to the mix, any notions of

11 comparability over time have even less meaning.

12

13 /

14

15 /

16

17 /

18

19

20

21

22

23

24

25

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Knox, Di-Reb 6A
Avista

1 The Company's cost of service methodology

2 presented in this case advocates only two changes from

3 the methodology found acceptable by this Commission in

4 the last general rate proceeding. As Commission Staff

5 witness Hessing points out on page 5 of his direct

6 testimony, the net result of these two changes benefit

7 Extra Large General Service customers without causing

8 extreme deviation from the prior method for any customer

9 group. Potlatch's recommended changes to cost of service

10 methodology should be rejected.

11 Q. Does this conclude your rebuttal testimony

12 in this proceeding?

13 A. Yes, it does.

14

15

16

17

18

19

20

21

22

23

24

25

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Knox, Di-Reb 7
Avista

1 (The following proceedings were had in

2 open hearing.)

3 MR. MEYER: And the witness is available

4 for cross.

5 COMMISSIONER SMITH: Thank you.

6 Mr. Shurtliff, do you have questions?

7 MR. SHURTLIFF: Briefly, Madam

8 Commissioner.

9

10 CROSS-EXAMINATION

11

12 BY MR. SHURTLIFF:

13 Q Ms. Knox, the purpose of a cost of service

14 study, I take it, is to seek to apply to different

15 classes of users the cost associated with providing that

16 service; is that correct?

17 A The purpose is to make a fair allocation of

18 costs to the different classes, yes.

19 Q In that regard, notwithstanding that

20 there's a lot of math that goes into it, notwithstanding

21 that there's a lot of empiric information that goes into

22 it, there are a number of judgment determinants that go

23 into a cost of service study, are there not?

24 A Yes.

25 Q Indeed, the question whether we use a

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Wilder, Idaho 83676 Avista

1 single peak or twelve coincident peaks or weighted

2 average peaks or whatever, that's a matter of judgment by

3 the expert, is it not?

4 A Yes, it is.

5 Q And in this case, you've applied a judgment

6 that the cost of service study that you've utilized and

7 that you promote here on behalf of Avista has elements

8 of, I think what's called, the basic customer method used

9 in the State of Washington; is that correct?

10 A I labeled it the basic customer method,

11 that's what they call it in the State of Washington.

12 It's a method that makes a clear delineation between

13 distribution plant that is directly associated with

14 individual customers and that which is connected to the

15 interconnected distribution system.

16 Q In that regard, in the State of Washington

17 the commission uses that method, do you know any other

18 jurisdictions that do?

19 A I know that the Utah Power & Light or

20 PacifiCorp use a method, they don't call it that, but it

21 makes the same demand and customer classification

22 differentiation as the basic customer --

23 Q Isn't it a fact --

24 A -- in Idaho.

25 Q Isn't it a fact that the Utah Power & Light

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Wilder, Idaho 83676 Avista

1 part of whatever it is now, both a summer and a winter

2 peak make a difference in what you ought to do in a cost

3 of service study?

4 A The time of the peaking I would not think

5 would have a difference on the classification of

6 distribution plant.

7 Q Did you do in your preparation some cost of

8 service that would use only the one peak of The

9 Washington Water Power Company to drive a test cost of

10 service study?

11 A No, I did not test that methodology.

12 Q Why not?

13 A I started with the methodology that we have

14 used in past cases and, you know, that kind of was the

15 basis for where you go with a cost of service. You start

16 with where you've been and then you look at what is the

17 system like now, are there any reasons to change, and I

18 found no reasons to move away from what we have had

19 accepted in this jurisdiction and in the Washington

20 jurisdiction, so I did not make a change to that area.

21 Q But somebody could propose such a change

22 and while you might disagree with it, it would be --

23 A That is true.

24 Q You did make some changes, though, from the

25 past cost of service study you previously utilized, did

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Wilder, Idaho 83676 Avista

1 you not?

2 A Right. I essentially made two changes.

3 The first change, as we were discussing, was the basic

4 customer. The reason that I chose not to pursue the

5 minimum size distribution system method that we had in

6 our previous cases in the '80s is that that information

7 had not been updated by our distribution engineering

8 people since that time and it was a matter of should we

9 update this study for this, you know, this particular

10 proceeding or should we look at alternative

11 methodologies.

12 I had done some things in the Washington

13 jurisdiction with the basic customer method and was very

14 happy with it and when looking at the choice of, you

15 know, requesting an updated study to go through 12 years

16 of data or to use a method that I felt was fair and that

17 had a very clear delineation of the types of plant, the

18 plant that can be directly attributable to the number of

19 customers and the type of plant that is associated with

20 demand, I chose not to request to have that minimum size

21 distribution study updated.

22 The other change that I made had to do with

23 how we treated administrative and general costs and in

24 the last couple of years, I'm sure this Commission is

25 well aware, we did the Idaho unbundling study and then

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Wilder, Idaho 83676 Avista

1 following that we also had an unbundled cost study in

2 Washington and the premise of that was to take the

3 methodology that had been used in our previous cases and

4 apply that and come up with functional costs, and the

5 method that was applied to administrative and general in

6 those past cases took -- it took those items and spread

7 them essentially by other operating and maintenance

8 expenses.

9 This is one way that we treat common costs

10 where we don't have a direct association with function

11 and when that was done, it put a particularly heavy

12 association with production that we felt was not

13 representative of the functional costs of, you know, the

14 causes of common costs and we wanted to look at it in

15 more detail.

16 Idaho Power in that Idaho unbundling study

17 had done a special study where they directly assigned as

18 much of the common costs as possible directly to the

19 functions and I actually had discussions with them on how

20 they went about that and we did a study here using the

21 same basic precepts of what responsibility area charged

22 those common costs and then we looked at what that area

23 does and if that group was associated with a particular

24 function, then we could directly assign those common

25 costs or the administrative and general costs.

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Wilder, Idaho 83676 Avista

1 When we did that, you know, it made a very

2 different allocation to the different functions and

3 following that, we were left with a group of costs; for

4 example, finance, which our accounting group who -- I

5 mean, they take information from all over the country,

6 not the country, the Company and they make use of it. Is

7 it associated with one group of customers? No. Is it

8 associated with one particular function of the Company?

9 No, it's associated with all functions of the Company.

10 Another general cost is my time. You know,

11 am I associated with the distribution or with

12 transmission or production? I do a cost study that talks

13 about all of them, but I am not associated with any one

14 and so looking at this group of common costs, which was a

15 large part of the administrative and general costs, we

16 had to come up with then a way to allocate those costs.

17 What I have done in this study is new.

18 It's not something that I know of that anyone else has

19 ever done and we had internal discussions and through our

20 own judgment came up with what we think is a fair

21 distribution of those costs by having some of them being

22 associated with the number of customers, with the idea

23 that if you have more customers, they will be generating

24 more transactions and, therefore, will cause more of

25 these general administrative costs, irrespective of how

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Wilder, Idaho 83676 Avista

1 large those transactions are.

2 Then the -- we also feel that in some ways

3 larger customers should bear some respective amount of

4 those costs. Because of their larger size, we do pay

5 more attention to them. There may be more things that

6 have to be done for larger customers than smaller

7 customers to capture that. We're not -- we did not

8 specifically classify to energy and customer. We simply

9 chose an allocator that has a customer and an energy

10 relationship to it in order to try to capture that, you

11 know, that size does make a difference on a portion of

12 these costs and size does not make a difference on other

13 portions of the costs, so we have a 60-40 customer/energy

14 relationship that's built into the allocator and that is

15 what we applied to this large group of common costs.

16 Q In making those determinations you

17 exercised judgment, did you not?

18 A Certainly.

19 Q And you looked at the pros and cons of the

20 exercise of that judgment, we can do it this way or we

21 can do it that way?

22 A Yes, we did.

23 Q And someone else could look at the like

24 information and come to a different conclusion; would

25 that be fair?

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Wilder, Idaho 83676 Avista

1 A That is true.

2 Q Would you agree with me that that cost of

3 service study, as you put it at page 3 of your direct

4 testimony, is a guide rather than written on stone

5 plates?

6 A Definitely, yes.

7 Q And so in that regard, are there other

8 factors beyond just the judgments that went into the cost

9 of service study that ought to form part of the

10 determination as to what is a reasonable cost to apply to

11 a particular body of customers?

12 A One of the things that we try to do when

13 you perform a cost of service study is you consider

14 fairness in all of those judgment calls and one of the

15 things I did, you may notice, I have one of my exhibits,

16 I believe it is 17, I performed alternative scenarios

17 where I tested out some of those judgments that went into

18 it and tried to see what would the difference be if we

19 made alternative choices on some of the key decisions,

20 and in doing so, the first thing I did is to compare it

21 against our previous case, the 1985 methodology that went

22 into that, and next I made an alternative decision

23 regarding production and transmission.

24 If, you know, you took one that was more

25 heavily weighted toward a demand allocator than an energy

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Wilder, Idaho 83676 Avista

1 allocator, what would the difference be and that is the

2 third alternative that's listed there. I also did a test

3 on my new common cost allocator, what would happen if I

4 made it 100 percent customer and what would happen if I

5 made it 100 percent energy in order to see the

6 sensitivity that is involved in that judgment call, and

7 in doing so, I look at all five of these and the one

8 thing that I see in common on all five of the scenarios

9 is that residential customers are underearning and extra

10 large general service customers are underearning.

11 Q If in the exercise of fairness you had

12 determined that as to those extra large customers it

13 would be fundamentally unfair to have a 12 coincident

14 peak cost of service study, but rather that we ought to

15 in fairness to those customers use a single peak, what

16 would that have done to the return?

17 A I prepared -- hold on. In looking at the

18 testimony of Dr. Peseau, I did a little thing where I ran

19 each individual item that he suggested be changed and if

20 I can find the right piece of paper.

21 Q I think you refer to that in your rebuttal

22 testimony, do you not?

23 A No. I did not go through the individual

24 things here. If you made the change to single peak,

25 extra large general service customers would be earning a

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Wilder, Idaho 83676 Avista

1 4.74 percent return. I didn't do the return ratio on

2 these, I just did the rate of return. Residential

3 service would have dropped to 3.57 percent return if you

4 choose a single coincident peak.

5 Q The residential would drop?

6 A The residential would drop, the extra large

7 general service would change. They would both still be

8 underearning.

9 Q And that was in reference to Dr. Peseau's?

10 A Right, by applying a single peak. I

11 actually -- the exhibit that he provided, I ran that

12 allocator through my model with that as the only change.

13 I did each of the five changes he made that way.

14 Q I'll leave that to Dr. Peseau. Did you in

15 your cost of service study, did you get into the area of

16 the question that is going to be raised with the next

17 witness, that is, and that the Staff raised, that is, the

18 question of this contributions in aid of construction as

19 to the distribution that --

20 A I'm sorry, could you rephrase the

21 question?

22 Q Well, there's a question as to the

23 recapture by the Company or the failure of recapture by

24 the Company of certain distribution costs. Are you

25 familiar with that at all?

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CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 A I know that that was one of the issues. I

2 have not dealt with it, no.

3 Q Is that an impact at all in your cost of

4 service study?

5 A I essentially take the numbers that are

6 agreed upon by the financial people. Mr. Falkner

7 prepares the pro forma results of operations. The

8 exhibit that he shows you is highly rolled up into

9 categories. I look at it on an individual account basis

10 and essentially I run Mr. Falkner's numbers through my

11 model. I generally do not get involved in the parts that

12 go into that.

13 MR. SHURTLIFF: Thank you. I have no

14 further questions, Ms. Knox.

15 COMMISSIONER SMITH: Mr. Ward.

16 MR. WARD: Thank you.

17

18 CROSS-EXAMINATION

19

20 BY MR. WARD:

21 Q Ms. Knox, I understand from your counsel's

22 statement at the opening that this is your first

23 experience as a witness in a full-blown rate case; is

24 that correct?

25 A This is true.

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Wilder, Idaho 83676 Avista

1 Q Notwithstanding that, I have to ask you a

2 couple of fairly tough questions. Let me direct your

3 attention -- I'm going to deal solely with your rebuttal

4 and I would appreciate it if you don't have a copy of

5 Dr. Peseau's testimony if your counsel could provide

6 one.

7 A I have that.

8 Q Okay. On page 1, lines 14 through 15 of

9 your rebuttal testimony, you say, referring to

10 Dr. Peseau's testimony, that it's designed to shift costs

11 away from his client customer group and incidentally onto

12 the residential customers, doing so without any real

13 support or justification. Do you see that?

14 A Yes, I do.

15 Q If you'd turn over to page 6 of your

16 testimony, you say at lines 7 through 9, "Mr. Peseau has

17 selectively applied a combination of alternative theories

18 each designed to shift costs away from his client

19 customer group and onto residential customers."

20 Now, let me start by asking you, do you

21 know how long Dr. Peseau has been working in this field?

22 A No, I do not.

23 Q So I take it you didn't go back to see if

24 he applied the same cost of service methodology, give or

25 take, that he's used for his career, throughout his

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Wilder, Idaho 83676 Avista

1 career?

2 A No, I did not.

3 Q And whenever this question of motives and

4 objectivity would come up when a former Commissioner was

5 here, he would generally interject with a roar and ask

6 who is there in this room who's without motives. Aren't

7 we all here for a reason, to advocate our position?

8 A Yes.

9 Q And the fact that Dr. Peseau may disagree

10 with you doesn't necessarily mean, does it, that he is

11 selecting his results to fit his agenda any more than

12 that would be true of you?

13 A The Company perspective is generally

14 unbiased with regard to which group of customers.

15 Q Well, let me pursue that just a moment with

16 you, Ms. Knox. Were you here when Mr. Matthews testified

17 yesterday?

18 A Yes, I was.

19 Q And in the course of my examination of your

20 CEO, I asked him, and I'll have to paraphrase, whether

21 the commercial class was a particular source of concern

22 with respect to competition and I'll have to paraphrase

23 to some degree, but he answered essentially yes, that

24 that was the class in which competition was most keenly

25 felt. Do you recall that?

800

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 A I do remember him saying that, yes.

2 Q Now, would the mere fact that your cost of

3 service study shows the commercial class with the highest

4 overall rate of return and, therefore, the need for a

5 lesser increase, would that necessarily justify us in

6 saying that you have designed your cost of service study

7 to achieve an agenda to promote your competitive

8 interests?

9 A The problem with the Schedule 11 and

10 Schedule 21 is the rate design that they acquired

11 throughout -- how they acquired it through the '70s and

12 '80s has resulted in basically overearning and you can

13 put any methodology you want to it, you're still going to

14 find that they earn more than unity. Simply because the

15 way the rates are currently designed, they are charged

16 more, No. 1 more, than other customers and, No. 2, in a

17 way that no matter -- as long as it has some relationship

18 to production and transmission and distribution, they

19 will come out higher than the other customers.

20 Q Ms. Knox, you may not have quite understood

21 my question. What I'm trying to get to is what a

22 slippery slope this business of motives is. If I were to

23 ask you, if I were to charge you with a question that

24 you've produced a cost of service study that favors your

25 competitive interests, wouldn't your answer be no, I

801

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 haven't?

2 A I'm sorry, could you say that again?

3 Q Let's drop that. On page 1, lines 18

4 through 19 -- oh, let me ask you one before I go on to

5 that, just a small item. On page 2, lines 5 through 10,

6 you basically say there that Potlatch did not take the

7 opportunity to challenge the Company's cost of service

8 methodology in WWP-E-98-1. Do you see that on page 8 --

9 on line 8?

10 A Yes.

11 Q Was that the unbundling case?

12 A Yes, it was.

13 Q Was there any money involved in that in

14 terms of rate increases to customers?

15 A No, very clearly there was not.

16 Q And do you really mean to suggest that if

17 an intervenor doesn't appear in a case that has no

18 revenue impact as far as that intervenor is concerned

19 that they forfeit their right to challenge a methodology

20 thereafter?

21 A No, I do not mean to say that. I believe I

22 was referring to the fact that he said contrary to

23 Avista's filings before the FERC and previous Idaho

24 Commission filings and I felt that that statement was

25 something, was untrue. Obviously, it had been before the

802

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 Idaho Commission before.

2 Q Well, that's what I want to follow up with

3 you on now with the statement on page 1, lines 18 through

4 19, that Mr. Peseau makes untrue assertions regarding

5 what this Commission has found acceptable for other Idaho

6 utilities, and let me pursue the specifics with you. If

7 you'd turn over to page 2, lines 22 through 23, you're

8 asked the question, "Mr. Peseau implies that the minimum

9 distribution system is the only distribution cost

10 classification methodology accepted by the Idaho

11 Commission, is this true?"

12 And your answer is, "No. PacifiCorp's Utah

13 Power & Light Idaho jurisdiction utilizes essentially,"

14 and you go on. Now, that exchange to me very clearly

15 says it's your assertion that Dr. Peseau said this is the

16 only system used in Idaho and you have cited UP&L as

17 evidence for the proposition that his supposed assertion

18 is untrue, that's what you meant to say, isn't it?

19 A Certainly.

20 Q All right. Now, would you take the copy of

21 Dr. Peseau's testimony that you have --

22 A Uh-huh.

23 Q -- and turn to pages 32 through 35 where he

24 has a discussion of basic customer versus minimum

25 distribution system?

803

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 COMMISSIONER KJELLANDER: Mr. Ward, could

2 you give us a second to catch up with you?

3 MR. WARD: Yeah.

4 Q BY MR. WARD: On pages 32 through 35 is his

5 discussion of the controversy over the minimum

6 distribution system. Now, if you need, Ms. Knox, I'll

7 give you a moment to look that over or do you recall it?

8 A I was looking at it right now.

9 Q Excuse me, I'm sorry.

10 A I have it right in front of me. Is there a

11 particular area on it that you were interested in?

12 Q Where is the assertion, this untruth that

13 you cite, that his proposal is the only method adopted in

14 Idaho? Let me assist you, if I may, Ms. Knox. The only

15 reference to the adoption by other states that I see in

16 reviewing his testimony is on page 32, lines 13 through

17 15, Dr. Peseau says, "While Ms. Knox is correct that the

18 basic customer method has been adopted in the Washington

19 jurisdiction," and then later on he again repeats the

20 reference to the Washington jurisdiction with regard to

21 the basic customer method and on the bottom of 32,

22 starting with the last line, line 24, he says, "The

23 minimum distribution system method was and remains the

24 primary jurisdiction cost method here in Idaho and

25 elsewhere."

804

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 How did you interpret that statement as a

2 statement that the only method ever adopted in Idaho is

3 the minimum distribution system?

4 A By stating that it was the primary cost

5 method as if it were the only cost method and, yes, that

6 is where I got that from.

7 Q You don't see a difference between primary

8 and only?

9 A There is room in the word "primary" for

10 other opinions to be held.

11 Q And isn't it true that in fact the minimum

12 distribution system method is used by Idaho Power?

13 A You know, I was reading Ms. Brill's

14 testimony on there and she makes a mention of something

15 called normalized minimum use and I'm not familiar with

16 normalized minimum use. I assume that it is similar to a

17 minimum size distribution system methodology.

18 Q And in fact, the same methodology had been

19 approved for your company, Avista, in prior cases here,

20 had it not?

21 A We have used that in prior cases, yes.

22 Q And in fact, with regard to your supposed

23 exception that proves this supposed absolute statement

24 wrong, what UP&L case are you referring to when you say

25 that they are different?

805

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 A What I did, I looked at what UP&L had

2 supplied in the unbundling case.

3 Q But --

4 A No, hold on a second, and after I had done

5 that, I called Mr. Taylor and in a telephone conversation

6 with him, I said, "In the Idaho unbundling case, we were

7 directed to use the methodology that was approved in our

8 prior cases," and I asked him, "Is this the methodology

9 that was approved in your prior cases?"

10 And he said in the 20 years that he had

11 been doing cost of service for PacifiCorp, he had never

12 done a minimum distribution system study.

13 Q Okay. Now, and just generally, by the way,

14 in Dr. Peseau's discussion of the competing methods, that

15 is, the method you proposed and the method Dr. Peseau

16 proposed, in the pages 32 through 35, doesn't he in fact

17 recite the background and the reasons why he chooses an

18 alternative to your proposal?

19 A He makes a case that's related to marginal

20 cost studies that he has done saying that distribution

21 plant is demand related, and, you know, he's very clear

22 and, yes, I agree with him, distribution plant is demand

23 related and then he goes on to talk about the different

24 categories of demand and then he makes a leap that I

25 could not follow that minimum size better emulates this

806

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 method that he prefers, which is not either of them, than

2 basic customer.

3 Q Would you say that because of your critique

4 that you have said that he's doing so without any real

5 support or justification?

6 A I did not see any support for why minimum

7 size was better than basic customer because distribution

8 plant is built with demand as a planning criteria.

9 Q Let's go on to the next issue and this has

10 to do with the use of a, what I'll call, 1CP versus 12CP

11 methodology, do you understand? You're familiar with

12 that dispute, are you not?

13 A Certainly.

14 Q And just for the record, "CP" means

15 coincident peak?

16 A Yes, it does.

17 Q All right. Now, let's go to page 3,

18 lines 4 through 5 of your testimony. Excuse me, that's

19 the question, obviously. On page 3 you say at lines 9

20 through 10, "Both Idaho Power and Utah Power and Light

21 studies also utilized twelve monthly averages for their

22 coincident peak allocators." Do you see that?

23 A Yes.

24 Q Do you see that testimony?

25 A Yes, I do.

807

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 Q Now, in what detail are you -- what level

2 of detail are you familiar with how Idaho Power uses its

3 coincident peak allocators?

4 A I looked at their last case and read the

5 Order related to their last case where they discuss their

6 weighted 12CP methodology.

7 Q Okay, and in fact, you mention that at

8 lines 20 through 22, it's weighted by the marginal cost

9 of capacity for different months.

10 A Yes, it is.

11 Q And doesn't that weighting produce a cost

12 of zero for six months?

13 A No.

14 Q You know or is the answer no or you don't

15 know?

16 A My recollection of the paper that I saw in

17 Ms. Brill's exhibit, there were only two months that had

18 zero in them.

19 Q Let me ask it another way: Doesn't it in

20 fact place the bulk of the weighting on three to four

21 months of peak periods?

22 A My recollection is that there were four or

23 five numbers in there that had good-sized weightings. I

24 really did not study it in detail.

25 Q Okay. Just taking up for the moment the

808

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 merits of your proposal for a 12CP allocator, isn't the

2 implication of a 12CP allocator that demand cost

3 causation is equal in all 12 months?

4 A What it reflects is that to fairly reflect

5 a demand cost you want to look at more than one hour out

6 of 8,760 because demand happens throughout the year and

7 by choosing a monthly which is a common time period by

8 which to measure demand, you know, Dr. Peseau brought it

9 up in his transmission, in the FERC how did they measure

10 it, they measure it by kilowatt month, so I don't feel

11 that a 12 month is an unreasonable selection of hours to

12 use for a demand allocator.

13 Q I don't want to beat this to death,

14 Ms. Knox, but let me ask you just one more question in

15 this vein. Are you suggesting that demand cost causation

16 is the same in the months of April, May, for instance, as

17 it is in January or December for Avista?

18 A The thing about demand is that you are

19 looking at a fixed cost. You have these items in place

20 and -- no, you would not say that there would be extra

21 costs during that time; however, you may plan for

22 maintenance of the system during those months because

23 they might be available at that time. There are all

24 kinds of planning criteria that go into the whole thing.

25 We are taking a bucket of dollars that we

809

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 represent as being demand. We are spreading it to many

2 customers over many kilowatt-hours and many kilowatts and

3 by trying to link it directly to cost causation, it's

4 extremely difficult to do, partially because that changes

5 from year to year and yet the plant that's in place does

6 not change from year -- I mean, it changes slightly, but

7 not greatly. It was built to provide service for many

8 years and if you look at a single year, for example, in

9 1998, the Idaho jurisdiction had, their peak occurred in

10 July at 1:00 o'clock in the afternoon which reflects a

11 different grouping of or a relative demand at that hour

12 than at 8:00 o'clock in the morning which is when the

13 January peaks occur. All of these things, if you do not

14 include anything other than a single hour, then you're

15 saying that a customer that uses demand in another month

16 doesn't have to pay for it.

17 Q Ms. Knox, moving on to the last issue I

18 want to discuss with you. On page 4, lines -- well, on

19 page 4, throughout that page, we have a discussion of the

20 method of allocating transmission costs. Do you recall

21 that testimony?

22 A Yes, I do.

23 Q And lines 5 through 12 you make some

24 assertions about how Idaho Power allocates its

25 transmission costs and it's sufficiently complicated I'm

810

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 going to pass over that for the moment, I'm going to pass

2 over it and leave it for Dr. Peseau, but I want to ask

3 you a question about your response on lines 15 through

4 19. There you say in response to a question about

5 Mr. Peseau's alleged statements, "At page 39 beginning at

6 line 5 Mr. Peseau states that Avista classifies

7 transmission costs 100 percent to demand before the

8 FERC. This is untrue, the FERC transmission cost

9 methodology addresses only functionalization."

10 Now, that in fact is a correct statement on

11 your part, but I would like to refer you, and I don't

12 think you have to turn to it, I'll read it real quickly,

13 the use of the word classification rather than

14 functionalization is not Dr. Peseau's, is it, it's my

15 word? Do you recall that?

16 A I'm sorry.

17 Q Here's the question and answer you're

18 referring to, "Does Avista classify transmission costs

19 100 percent to demand in all its filings and proceedings

20 before the FERC?

21 Yes.

22 Are other utilities and other users of

23 Avista's transmission system charged transmission rates

24 based on classifying 100 percent of transmission costs to

25 demand?

811

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 Yes."

2 Now, you are correct that in shoddy

3 language on my part I referred to that as classification

4 rather than functionalization, but is your implication

5 about how the costs are actually spread correct; in other

6 words, those costs all go to demand, don't they?

7 A Those costs are all put into a single

8 figure, a revenue requirement number for the entire

9 system. They put a price on it, on the entire system,

10 even though most of it is used for retail load, and the

11 price that they put on it is a demand charge. They could

12 as easily have divided it by energy if they chose to.

13 MR. WARD: Madam Chair, may I approach the

14 witness?

15 COMMISSIONER SMITH: You may, Mr. Ward.

16 MR. WARD: I believe we're to No. 212.

17 (Mr. Ward approached the witness.)

18 (Potlatch Corporation Exhibit No. 212

19 was marked for identification.).

20 Q BY MR. WARD: I've handed you what's been

21 marked for identification as a three-page exhibit,

22 Exhibit No. 212. Ms. Knox, do you recognize what that

23 is?

24 A It's part of the transmission, it looks

25 like the FERC schedule for transmission.

812

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 Q Do you recognize that that's Avista's rate

2 design?

3 A No, but I recognize the $1.40, but I'm

4 really not familiar with the FERC tariff.

5 Q All right, let me represent to you that it

6 is for the moment unless somebody wants to correct me.

7 Isn't it clear in looking at page 1 and page 3 that in

8 fact all of these rates are as Dr. Peseau testified

9 demand rates only?

10 A Yes, sir, and I state very clearly that the

11 rate design for the transmission system is demand.

12 Q And if you didn't regard -- if you

13 regarded, if FERC regarded any portion of the

14 transmission system in cost causation terms as energy

15 driven, wouldn't they have an energy rate as well?

16 A I cannot speak for the FERC. You know, you

17 charge by what you choose to charge it by. That may be

18 true.

19 MR. WARD: Thank you. That's all I have.

20 COMMISSIONER SMITH: Thank you, Mr. Ward.

21 Mr. Woodbury, do you have questions?

22 MR. WOODBURY: Thank you, Madam Chair.

23 Staff has no questions.

24 COMMISSIONER SMITH: Do we have questions

25 from the Commission? I just have one because I got

813

CSB REPORTING KNOX (X)
Wilder, Idaho 83676 Avista

1 confused.

2

3 EXAMINATION

4

5 BY COMMISSIONER SMITH:

6 Q When you talked about the July peak in '98,

7 were you saying that the Avista system in '98 peaked in

8 July?

9 A It was actually very close. When you

10 combine Washington and Idaho, it was slightly -- the

11 January peak was just slightly higher, but when I looked

12 at -- you wouldn't believe the paper that you have to

13 look through for this, but the load information that we

14 get in order to get down to that net system load for --

15 I'm not talking, of course, about 1997, but about 1998,

16 July 22nd, 1998, in Idaho was their peak.

17 Q Okay, thank you.

18 A Even though the system as a whole peaked in

19 January.

20 COMMISSIONER SMITH: Mr. Meyer.

21 MR. MEYER: Thank you. You covered off on

22 the one clarification on the July peak that I wanted to

23 talk about, just real briefly.

24

25

814

CSB REPORTING KNOX (Com)
Wilder, Idaho 83676 Avista

1 REDIRECT EXAMINATION

2

3 BY MR. MEYER:

4 Q The Commission Staff in this proceeding has

5 reviewed your cost of service study, hasn't it?

6 A Yes, they have.

7 Q They found it acceptable?

8 A Yes, they did.

9 Q Do some of the adjustments that you made in

10 your cost of service study favor Schedule 25 while others

11 go in the opposite direction?

12 A Yes, that's true. I stated that in my

13 rebuttal testimony as well. There are two changes from

14 the prior methodology. The one is the change away from

15 minimum distribution system and that one, as Dr. Peseau

16 points out, does take or it does add costs to extra large

17 general service customers; however, the administrative

18 and general change favors extra large general service

19 customers and the net effect of the two is favorable to

20 extra large general service customers.

21 MR. MEYER: Thank you very much. That's

22 all I have.

23 COMMISSIONER SMITH: Thank you, Mr. Meyer.

24 Thank you, Ms. Knox.

25 (The witness left the stand.)

815

CSB REPORTING KNOX (Di)
Wilder, Idaho 83676 Avista

1 MR. MEYER: Our last witness for this

2 portion of the proceedings, Mr. Hirschkorn.

3

4 BRIAN J. HIRSCHKORN,

5 produced as a witness at the instance of Avista

6 Corporation, having been first duly sworn, was examined

7 and testified as follows:

8

9 MR. MEYER: As a preliminary matter, I

10 believe I circulated to everyone an additional exhibit at

11 the start of the proceeding that really updated the last

12 several pages of his prior exhibit to reflect the revised

13 revenue requirement. I just want to make sure that

14 everyone still has that. It's marked as Exhibit No. 26,

15 so we have extra copies if some do not have it. Do you

16 have that?

17 MR. WARD: I'm sure I do, but give me

18 another one.

19 MR. MEYER: Okay.

20 COMMISSIONER KJELLANDER: Could I get a

21 fresh copy as well?

22 MR. MEYER: I've got more here. Let me

23 just dig through this.

24 COMMISSIONER KJELLANDER: They're sharing

25 up here.

816

CSB REPORTING HIRSCHKORN
Wilder, Idaho 83676 Avista

1 MR. MEYER: That's what happens when I'm

2 given custody of all the copies.

3 COMMISSIONER KJELLANDER: I'm actually

4 fine, thank you.

5

6 DIRECT EXAMINATION

7

8 BY MR. MEYER:

9 Q Okay, with that, are you ready to proceed?

10 A Yes.

11 Q For the record, please state your name and

12 your employer.

13 A My name is Brian Hirschkorn and I'm

14 employed by Avista Corporation.

15 Q And have you prepared both direct and

16 rebuttal testimony in this proceeding?

17 A Yes, I have.

18 Q Do you have any changes to make to either

19 your direct or rebuttal?

20 A I have two minor changes, one to my direct

21 testimony and one to my rebuttal. On page 17 of my

22 direct testimony, line 11, the word "half" should read

23 "one-quarter," and on page 8 of my rebuttal testimony,

24 line 20, the word "inconsistent" should read

25 "consistent." Those are the only two changes that I

817

CSB REPORTING HIRSCHKORN (Di)
Wilder, Idaho 83676 Avista

1 have.

2 Q Thank you; so if I were to ask you the

3 questions that appear in your direct and rebuttal

4 testimony, would your answers be the same?

5 A Yes, they would.

6 Q Then are you also sponsoring what have been

7 marked for identification as Exhibits 19, 20, 21 and 26?

8 A Yes, I am.

9 Q Any changes to make to those?

10 A No.

11 Q And the information contained therein is

12 true and correct?

13 A Yes, it is.

14 MR. MEYER: With that, I move for the

15 spreading of his testimony and the admission of those

16 exhibits.

17 COMMISSIONER SMITH: If there is no

18 objection, it is so ordered.

19 (Avista Corporation Exhibit Nos. 19-21

20 & 26 were admitted into evidence.)

21 (The following prefiled direct and

22 rebuttal testimony of Mr. Brian Hirschkorn is spread upon

23 the record.)

24

25

818

CSB REPORTING HIRSCHKORN (Di)
Wilder, Idaho 83676 Avista

1 Q. Please state your name, business address

2 and present position with The Washington Water Power

3 Company?

4 A. My name is Brian J. Hirschkorn and my

5 business address is East 1411 Mission Avenue, Spokane,

6 Washington. I am presently assigned to the Rates

7 Department as a Senior Rate Accountant.

8 Q. Q. Would you briefly describe your

9 duties?

10 A. My primary areas of responsibility include

11 electric and gas rate design, customer usage and revenue

12 analysis, and tariff administration.

13 Q. Would you briefly describe your educational

14 background?

15 A. I graduated from Washington State

16 University in 1978 with Bachelor degrees in Business

17 Administration and Accounting.

18 Q. Have you previously testified before the

19 Commission?

20 A. Yes. I have testified before this

21 Commission in several prior rate proceedings as a rate

22 design and special contract witness.

23 Q. What is the scope of your testimony in this

24 proceeding?

25 A. My testimony in this proceeding will cover

819

Hirschkorn, Di 1
WWP

1 the spread of the proposed annual revenue increase of

2 $14,223,000, or 11.6%, among the Company's electric

3 general service schedules in the State of Idaho and the

4 design of the proposed rates within each of the

5 schedules. I am also responsible for the revenue

6 normalization adjustment.

7 Q. Are you sponsoring any exhibits to be

8 introduced in this proceeding?

9 A. Yes. I am sponsoring Exhibit Nos. 19, 20

10 and 21, which were prepared under my supervision and

11 direction.

12 Q. Would you please explain what is contained

13 in Exhibit No. 19?

14

15 /

16

17 /

18

19 /

20

21

22

23

24

25

820

Hirschkorn, Di 1A
WWP

1 A. Exhibit No. 19 is a copy of the Company's

2 present rates governing electric service in the State of

3 Idaho, which are on file with this Commission as a part

4 of the Company's tariff, IPUC No. 25.

5 Q. Turning now to Exhibit No. 20, would you

6 please state what is contained in that Exhibit?

7 A. Exhibit No. 20 contains the proposed

8 electric rates and schedules which are being filed with

9 the Commission as a part of our revised tariff, IPUC

10 No. 25.

11 Q. Could you please explain what is contained

12 in Exhibit No. 21?

13 A. Exhibit No. 21, contains information

14 regarding the Company's proposed rate spread and rate

15 design, which is discussed in more detail later in my

16 testimony.

17

18 REVENUE NORMALIZATION ADJUSTMENT

19 Q. Would you please describe the "revenue

20 normalization adjustment" which you have referred to?

21 A. The revenue normalization adjustment

22 represents the difference between the company's actual

23 recorded retail revenues during the test period and

24 retail revenues on a forward-looking basis based on known

25 and measurable changes (pro forma). The total revenue

821

Hirschkorn, Di 2
WWP

1 normalization adjustment increases Idaho revenues by

2 $2,580,000 and net operating income by $1,639,000, as

3 shown in column PF3 on page 7 of Exhibit No. 11. The

4 adjustment consists of three primary components:

5 1) repricing recorded customer usage (adjusted for known

6 and measurable changes) at present tariff rates in

7 effect, 2) adjusting customer loads and revenue to a

8 calendar-year basis (unbilled revenue adjustment), and

9 3) weather normalizing customer usage and revenue. The

10 rates used to

11

12 /

13

14 /

15

16 /

17

18

19

20

21

22

23

24

25

822

Hirschkorn, Di 2A
WWP

1 reprice recorded customer usage are the present tariff

2 rates in effect excluding Tax Adjustment Schedule 58,

3 Schedule 66 - Temporary Power Cost Adjustment (PCA),

4 Schedule 91 - Energy Efficiency Rider Adjustment. The

5 primary factors reflected in the repricing portion of the

6 adjustment are: 1) the elimination of temporary refunds

7 associated with PCA Schedule 66, 2) pricing the energy

8 usage for customers acquired from PacifiCorp. at the

9 Company's rates, and 3) reflecting expiration of the

10 Company's Direct Access and Delivery Service (DADS) pilot

11 program by repricing the usage for those customers at

12 "full service" tariff rates.

13 Q. Could you please explain that portion of

14 the revenue normalization adjustment associated with

15 customers acquired from PacifiCorp.?

16 A. In the Commission's Order Nos. 25844,

17 25801, and 25753 in Case No. WWP-E-94-1, the Commission

18 approved the purchase by the Company of PacifiCorp.'s

19 North Idaho distribution properties. With the purchase,

20 the Company became the electric service provider to

21 approximately 9,600 former PacifiCorp. customers in and

22 around the cities of Clark Fork, Hope, East Hope, Old

23 Town, Priest River and Sandpoint. Beginning in January

24 1995, the Company began providing service under a

25 four-year rate transition plan. The transition plan

823

Hirschkorn, Di 3
WWP

1 provided that these customers be served at PacifiCorp's

2 rates less a 1% rate reduction until January 1999, at

3 which time they would be transferred to the Company's

4 comparable rate schedules. The pro forma revenues

5 reflect the revenue for these customers under the

6 Company's rates, and a portion of the revenue

7 normalization adjustment reflects the difference between

8 the revenue at the Company's rates and actual 1997

9 revenues under the "transition" rates.

10 Q. Would you briefly describe the unbilled

11 revenue portion of the revenue

12

13 /

14

15 /

16

17 /

18

19

20

21

22

23

24

25

824

Hirschkorn, Di 3A
WWP

1 normalization adjustment?

2 A. As billed/recorded usage and revenue for

3 the test period does not represent actual usage by

4 customers during the calendar test period, the unbilled

5 revenue adjustment is necessary to estimate actual

6 consumption during the calendar year. The adjustment

7 results from a detailed examination of billed consumption

8 during the beginning and end of the test year. This

9 component of the adjustment decreases revenues by

10 $1,286,000.

11 Q. Why is the amount of the pro forma unbilled

12 revenue different from the amount which is recorded on an

13 actual basis?

14 A. The pro forma level excludes a prior period

15 adjustment of $1,356,000 which was included in the actual

16 results. Additionally, the pro forma unbilled revenue is

17 a more detailed estimate as compared to the amount

18 recorded on an actual basis and utilizes the present

19 tariff rates in effect to determine the amount of the

20 revenue adjustment.

21 Q. Would you briefly describe the weather

22 normalization adjustment which is included in the

23 Company's revenue normalization adjustment?

24 A. Yes. The weather normalization adjustment

25 provides an adjustment to revenues based on normal as

825

Hirschkorn, Di 4
WWP

1 compared to actual weather during the test year. A

2 linear regression analysis is run using 5.5 years of

3 historical usage per customer and actual degree-day data

4 for each rate schedule. If there is a strong correlation

5 between usage and the number of degree days, that

6 schedule is considered to be "weather-sensitive" and the

7 customer use per degree-day (coefficient) resulting from

8 the regression analysis is used as an estimate of the

9 weather sensitivity. The weather normalization

10 adjustment is then

11

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22

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24

25

826

Hirschkorn, Di 4A
WWP

1 determined for each weather-sensitive schedule by taking

2 the difference between actual and normal degree-days

3 multiplied by the use/degree day multiplied by the number

4 of customers and the result is then priced using the

5 present rates in effect for each schedule. The weather

6 normalization component increases revenue by $959,000 for

7 1997, representing the fact that the weather in the

8 Company's service area was warmer than normal during the

9 test year.

10

11 RATESPREAD

12 Q. Would you please review the Company's

13 present rate schedules and the types of electric service

14 offered under each?

15 A. Yes. The Company presently provides

16 electric service under Residential Service Schedule 1,

17 General Service Schedule 11, Large General Service

18 Schedule 21, Extra Large General Service Schedule 25, and

19 Pumping Service Schedule 31. Additionally, the Company

20 provides Street Lighting Service under Schedules 41-46,

21 and Area Lighting Service under Schedules 47 and 49. The

22 following table shows the type of customer and the number

23 of customers served (as of November 1998) under each of

24 the schedules (except street and area lighting):

25

827

Hirschkorn, Di 5
WWP

1 Schedule Type of Customer No. Of Customers

2 Residential Sch. 1 Residential 86,100

3 General Sch. 11 Small Commercial/
less than 50 kw 15,200
4
Lge. General Sch. 21 Med.-Lge. Comm. &
5 Industrial/over 50 kw 1,730

6 Ex. Lge. General Lge. Comm. & Industrial/
Sch. 25 over 2,500 kw 14
7
Pumping Sch. 31 Agriculture & other
8 water pumping 760

9

10 /

11

12 /

13

14 /

15

16

17

18

19

20

21

22

23

24

25

828

Hirschkorn, Di 5A
WWP

1 Q. Does the Company serve any special contract

2 customers in Idaho?

3 A. Yes, but only one. The Company serves

4 Potlatch Corporation's manufacturing plant in Lewiston

5 under a special (non-tariff) electric service agreement,

6 which I will discuss in more detail later in my

7 testimony.

8 Q. Could you please explain how the Company

9 proposes to spread the overall revenue increase of

10 $14,223,000 among the various service schedules?

11 A. Yes. The Company is proposing the

12 following revenue/rate increase by service schedule:

13 Proposed Increase by Rate Schedule

14 Residential Service Schedule 1 15.4%

15 General Service Schedule 11 7.5%

16 Large General Service Schedule 21 10.7%

17 Extra Large General Service Schedule 25 16.4%

18 Pumping Service Schedule 31 9.6%

19 Street & Area Lighting Schedules 41-49 13.0%

20

21 This information is also shown on Page 1 of

22 Exhibit No. 21. The proposed revenue increases shown in

23 the table above compare to a revenue increase of 12.9% if

24 applied uniformly to each of the schedules (excluding the

25 Potlatch special contract). No rate change is applied to

829

Hirschkorn, Di 6
WWP

1 the special contract with Potlatch as the rates for

2 service are determined under the contract and are

3 estimated as part of the adjustment which normalizes

4 Potlatch contract revenues, as shown on Page 7 of Exhibit

5 No. 11. The total increase in revenue under the Potlatch

6 contract is estimated to be $1.4 million, based on the

7 difference

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15

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18

19

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21

22

23

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25

830

Hirschkorn, Di 6A
WWP

1 between estimated rates for the period July 1999-June

2 2000 and 1997 actual rates for service.

3 Q. What rationale did the Company use in its

4 proposed spread of the overall revenue increase to the

5 various rate schedules?

6 A. The Company utilized the results of the

7 cost of service study, as sponsored by Company Witness

8 Knox, as a guide in developing the proposed rate spread.

9 The primary goal of the proposed rate spread is to move

10 the rates of return of the individual schedules closer to

11 the Company's overall rate of return (unity) so that all

12 customers contribute fairly to the cost of service. The

13 table below shows the relative rates of return by

14 schedule before and after the proposed increases are

15 applied. The relative rate of return is determined by

16 dividing the rate of return for each schedule by the

17 overall rate of return for the Company's Idaho electric

18 operations. This information is also shown on Page 2 of

19 Exhibit No. 21.

20

21

22

23

24

25

831

Hirschkorn, Di 7
WWP

1 Relative Rates of Return by Rate Schedule

2 Before After
Increase Increase
3

4 Residential Service Schedule. 1 0.57 0.71

5 General Service Schedule 11 1.88 1.60

6 Large General Service Schedule 21 1.45 1.31

7 Extra Large General Service
Schedule 25 0.64 0.77
8
Pumping Service Schedule 31 1.53 1.36
9
Street & Area Lighting
10 Schedules 41-49 1.09 1.06

11 Potlatch Special Contract 1.78 1.31

12

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17 /

18

19

20

21

22

23

24

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832

Hirschkorn, Di 7A
WWP

1 As shown, the relative rates of return for all of the

2 service schedules move approximately one-third of the way

3 toward unity (1.00) after application of the proposed

4 revenue increase by schedule.

5 Q. Why isn't the present rate of return under

6 Residential Schedule I closer to unity?

7 A. As the Commission is aware of, the Company

8 has not had a general electric rate increase since 1986.

9 Since that time, natural gas has become the predominant

10 choice for space-heating by customers. Where electricity

11 was the primary heating source for most residential

12 customers in the early 1980's, electricity is now the

13 primary heating source for only 22% of residential

14 customers, whereas natural gas is the primary source for

15 53%. As a result, average use per customer decreased by

16 10% during that time, from 13,941 to 12,535 kwhs per

17 year. Since 1986, the number of residential customers

18 served by the Company (including customers acquired from

19 PacifiCorp.) has increased by 41% whereas residential

20 energy usage and revenue have increased only 27%. With

21 the addition of new customers, the (embedded) average

22 cost of providing service to residential customers has

23 increased. The Company presently does not have a

24 customer charge under Residential Schedule 1, therefore,

25 nearly all fixed costs of providing service must be

833

Hirschkorn, Di 8
WWP

1 recovered through the energy charges. As average energy

2 use (and revenue) per customer has declined and average

3 fixed costs have increased, the rate of return for

4 residential service has fallen from 9.7% to 3.9% since

5 1986.

6 Q. Is the Company concerned with the level of

7 increase(s) which it is proposing to Residential Schedule

8 1 and to its large industrial and commercial customers

9 served under Schedule 25?

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18

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22

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834

Hirschkorn, Di 8A
WWP

1 A. Yes it is. However, as stated in Company

2 Witness Dukich's testimony, while prices for other goods

3 and services have increased by 53% during the past 12

4 years, the Company's electric rates have essentially

5 remained the same. If the Company would have implemented

6 an annual rate change for these schedules since 1986

7 equal to the proposed increase in this filing, that

8 annual increase would have amounted to 0.9% per year,

9 which would have went relatively unnoticed in customers'

10 bills. During that same time period, the cost to provide

11 electric service to these customers has been subsidized

12 by the rates charged to other commercial and industrial

13 customers (Schedules 11 and 21), and it is appropriate to

14 begin to reduce this degree of subsidization in the

15 future.

16 While the Company is concerned with the level of

17 the proposed increases to Schedules 1 and 25 customers,

18 it is also concerned about the level of the proposed

19 increases to commercial and industrial customers served

20 under Schedules 11 and 21, as these customers are

21 presently paying rates well in excess of the cost of

22 providing service, based on the Company's cost of service

23 study. The Company faces competition for service to new

24 customers from several electric cooperatives in various

25 areas of North Idaho. The commercial and industrial

835

Hirschkorn, Di 9
WWP

1 rates offered by these cooperatives are lower than the

2 Company's present rates, whereas their residential rates

3 are generally higher than those offered by the Company.

4 The proposed increases to Schedules 11 and 2 1, of 7.5%

5 and 10.7% respectively, will make the Company's rates for

6 these customers even less competitive.

7 Q. What would the relative rates of return by

8 schedule be if the Company spread the proposed increase

9 on a uniform percentage basis?

10 A. Shown below is a comparison of the relative

11 rates of return under present

12

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18

19

20

21

22

23

24

25

836

Hirschkorn, Di 9A
WWP

1 rates, the proposed revenue increase of $14,223,000

2 applied on a uniform percentage basis (12.9%), and the

3 proposed spread of the revenue increase:

4 Present Equal% Proposed

5 Residential Service Sch. 1 0.57 0.66 0.71

6 General Service Sch. 11 1.88 1.75 1.60

7 Large General Service Sch. 21 1.45 1.36 1.31

8 Extra Large General Service
Sch. 25 0.64 0.71 0.77
9
Pumping Service Sch. 31 1.53 1.44 1.36
10
Street & Area Lighting
11 Schs. 41-49 1.09 1.06 1.06

12

13 As shown, spreading the proposed revenue increase on a

14 uniform percentage basis would result in a slight

15 movement toward unity in the rates of return for the

16 service schedules, whereas the proposed spread results in

17 additional movement toward unity.

18 Q. Why isn't the Company proposing rates which

19 result in all rate schedules contributing a rate of

20 return equal to the Company's proposed return (unity)?

21 A. The Company also considered other factors

22 such as rate and revenue stability in its proposed spread

23 of the overall revenue increase. The Company believes

24 that the proposed rate spread achieves the goal of moving

25 the individual schedule rates of return closer to unity

837

Hirschkorn, Di 10
WWP

1 without compromising these other rate design

2 considerations. The following table shows the revenue

3 increase (decrease) percentage to each schedule which

4 would be necessary to achieve unity:

5

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8 /

9

10 /

11

12

13

14

15

16

17

18

19

20

21

22

23

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838

Hirschkorn, Di 10A
WWP

1 Residential Service Sch. 1 29.8%

2 General Service Schedule 11 (13.8)%

3 Large General Service Schedule 21 (3.2)%

4 Extra Large General Service Schedule 25 28.4%

5 Pumping Service Schedule 31 (5.6)%

6 Street & Area Lighting Schedules 41-49 9.6%

7

8 As shown, with necessary rate increases of nearly

9 30% to Schedules 1 and 25, a phase-in toward unity will

10 result in more rate stability for customers served under

11 these schedules. The Company proposes a two-or

12 three-part phase-in of rates necessary to result in rates

13 of return by schedule which are at or near unity, with

14 this filing reflecting the first part of this phase-in.

15 Because of the present disparity in the rates of return

16 among the various schedules, coupled with the level of

17 the total proposed revenue increase in this filing, the

18 Company believes that the proposed (one-third) movement

19 toward unity is reasonable in this proceeding.

20 Additionally, different cost-of-service studies can

21 utilize different allocation methodologies for major cost

22 categories. As shown in Exhibit No. 17 sponsored by

23 Company Witness Knox, the proposed rate spread will yield

24 results which are similar when applied to other

25 reasonable cost-of-service study results, i.e.,

839

Hirschkorn, Di 11
WWP

1 Residential Schedule 1 will not exceed unity under a

2 different study.

3 Q. When would you propose that the second part

4 of this "two-or three-part rate phase-in" occur?

5 A. The Company has no specific plans at this

6 time as to when that would occur.

7

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13

14

15

16

17

18

19

20

21

22

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840

Hirschkorn, Di 11A
WWP

1 Q. Is there additional information which you

2 propose that the Commission consider regarding the spread

3 of the proposed increase?

4 A. Yes. If the Commission approves a revenue

5 increase that is less than the increase requested, the

6 Company proposes that the Commission consider a rate

7 spread which moves the rates of return for the Company's

8 general service schedules even closer to unity than the

9 proposed one-third movement.

10

11 POTLATCH SPECIAL CONTRACT

12 Q. Would you please describe the present

13 electric service agreement between the Company and

14 Potlatch Corporation?

15 A. The present electric service agreement

16 between the Company and Potlatch Corporation is actually

17 a purchase and sale agreement, whereby the Company

18 purchases 50 to 55 average megawatts of generation from

19 Potlatch's Lewiston plant and the Company sells energy

20 and capacity to Potlatch for its total load requirements

21 at the plant. The agreement became effective January 1,

22 1992 and will expire December 31, 2001. Both the

23 purchase and sales rates were negotiated between the two

24 companies and are shown in the agreement, which was filed

25 with the Commission in Case No. WWP-E-91-5. Prior to

841

Hirschkorn, Di 12
WWP

1 January 1992, Potlatch's generation was used to serve a

2 major portion of their load requirements at the plant.

3 The agreement resulted in both incremental purchased

4 power and incremental retail sales to the Company. As

5 purchase power costs are normally allocated between

6 jurisdictions and retail sales are recorded on a situs

7 basis, normal ratemaking treatment of the agreement would

8 have resulted in an increase in the Company's Idaho net

9 operating income (benefit to the Company's other Idaho

10 customers)

11

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17

18

19

20

21

22

23

24

25

842

Hirschkorn, Di 12A
WWP

1 and a decrease in the Company's Washington net operating

2 income (disbenefit to Washington customers). In order to

3 minimize this jurisdictional result, the Company

4 proposed, and the Commission approved in Order No. 23858,

5 an allocation of the revenues associated with Potlatch's

6 incremental load requirement to match the allocation of

7 the incremental amount of purchased power and associated

8 costs.

9 Q. Could you please describe the purchase and

10 sales rates contained in the Agreement?

11 A. Both the purchase and sales rates were

12 negotiated between the two companies as part of the

13 overall Agreement. The rates to be paid to Potlatch for

14 purchased power were estimated to be 4.15 cents per

15 kilowatt-hour (kwh) on a ten-year levelized basis in 1992

16 dollars, which was significantly less than the Company's

17 avoided cost for a similar product at that time. The

18 average rate paid to Potlatch during 1997 was 4.4 cents

19 per kwh.

20 The Company provides both firm and interruptible

21 energy to Potlatch. Twenty-five (25) average megawatts

22 are provided to Potlatch on an interruptible basis at

23 non-firm market rates and a present monthly fixed charge

24 of approximately $48,000. Firm capacity is provided to

25 Potlatch at a monthly rate of $7.72 per kilovolt-ampere

843

Hirschkorn, Di 13
WWP

1 (kva), which was based on the estimated cost of long-term

2 capacity at the time the Agreement was negotiated. The

3 energy sales rates are based on actual non-firm market

4 rates, but are subject to a minimum and maximum which

5 escalate approximately 4% per year.

6 Q. How do the present firm sales rates under

7 the Agreement compare to the Company's present and

8 proposed rates for Extra Large General Service Schedule

9 25?

10 A. The average firm sales rate to Potlatch

11 during 1997 was 3.44 cents per

12

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16

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18

19

20

21

22

23

24

25

844

Hirschkorn, Di 13A
WWP

1 kwh and the estimated rate for the July 1999-June 2000

2 period is 3.73 cents per kwh. This compares with present

3 and proposed average rate for Schedule 25 of 3.04 cents

4 and 3.54 cents, respectively.

5

6 RATE DESIGN

7 Q. Could you please describe what is shown on

8 Page 3 of Exhibit No. 21?

9 A. Yes. Page 3 shows a comparison of the

10 present and proposed rates within each of the Company's

11 electric service schedules.

12 Q. Could you please explain what is shown on

13 Page 4 of this Exhibit?

14 A. Page 4 shows information taken from the

15 cost of service study sponsored by Company Witness Knox.

16 This page shows cost per billing unit (kwh, kw, and no.

17 of customers) information for each service schedule based

18 on the cost allocation/assignment on the basis of energy,

19 demand, or number of customers. Comparing these costs to

20 the present and proposed rates under each of the

21 Company's service schedules shown on Page 3, it is clear

22 that much of the costs which are allocated based on

23 demand or number of customers are recovered through the

24 energy charges of the various schedules.

25 Q. Could you please describe the present rate

845

Hirschkorn, Di 14
WWP

1 design within Residential Schedule 1?

2 A. Yes. Residential Schedule 1 is presently a

3 three-block inverted rate structure with the three blocks

4 being from 0-600 kwhs (4.181 cents/kwh), 601-1,300 kwhs

5 (4.945 cents/ kwh), and all kwhs over 1,300 (5.591

6 cents/kwh). There is also a present monthly minimum

7 charge of $8.50, whereby customers can use up to 203 kwhs

8 per month for $8.50.

9

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15

16

17

18

19

20

21

22

23

24

25

846

Hirschkorn, Di 14A
WWP

1 Q. Is the Company proposing any changes to the

2 present rate structure under Residential Schedule 1?

3 A. Yes. The Company is proposing a new

4 customer/basic charge of $5.50 per month and the

5 elimination of the present minimum charge of $8.50 per

6 month. Additionally, the Company is proposing a

7 reduction in the number of energy rate blocks from three

8 to two; the present energy tail-block (over 1,300 kwhs)

9 would be eliminated and the proposed rate blocks would be

10 0-600 kwhs and over 600 kwhs.

11 Q. Why is the Company proposing to eliminate

12 the present monthly minimum charge of $8.50 and replace

13 it with a customer charge of $5.50 per month?

14 A. The present monthly minimum charge under

15 Residential Schedule 1 is not representative of the costs

16 of providing service to customers served under the

17 Schedule. The present minimum charge is only billed to

18 those customers who use 203 kwhs or less during a month,

19 representing only about 8% of the total bills issued. As

20 a result of this rate structure, nearly all of the fixed

21 costs of providing service are recovered through the

22 energy charge(s). Further, because of the present

23 inverted rate structure under Residential Schedule 1,

24 much of the fixed costs of providing service to low usage

25 customers are actually recovered from other higher usage

847

Hirschkorn, Di 15
WWP

1 customers served under the Schedule.

2 A monthly basic charge would be billed in addition

3 to the energy charges and would serve to recover a

4 portion of the fixed costs of service from all customers.

5 The proposed monthly basic charge of $5.50 per month

6 would approximately recover the average embedded cost for

7 a service line, a meter, meter reading, and billing. The

8 Company is not purporting that these should be the only

9 costs recovered through the basic charge, but rather,

10 given the total changes proposed to Schedule 1, that it

11 is a reasonable

12

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18

19

20

21

22

23

24

25

848

Hirschkorn, Di 15A
WWP

1 level to establish in this case. These costs are shown

2 on Line 5, Page 5 of Exhibit No. 21. These costs compare

3 with total customer allocated costs from the Company's

4 cost of service study of $14.96 per customer per month,

5 as shown on line 9, column (a) on Page 4 of Exhibit

6 No. 21.

7 Q. Why is the Company proposing to reduce the

8 number of rate blocks from three to two under Residential

9 Schedule I?

10 A. Again, the present inverted rate structure

11 does not reasonably reflect the cost of providing service

12 to residential customers. As a result of the inverted

13 structure, many of the fixed costs to providing service

14 are recovered through the higher-rate second and third

15 blocks under the schedule. The Company has had the

16 present three-block inverted rate structure in effect

17 since 1980. This rate structure was implemented to send

18 a price signal to residential customers that reflected

19 the higher incremental cost of new generating resources

20 at that time. Large-scale generating plants are no

21 longer being built and the present inverted rate

22 structure is no longer representative of the incremental

23 cost of energy.

24 Since 1985, use per residential customer has

25 declined by 10%. Much of this decrease was the result of

849

Hirschkorn, Di 16
WWP

1 a general shift from electricity to natural gas as the

2 economical heating fuel of choice. Presently, 53% of the

3 Company's Idaho residential customers use natural gas as

4 their primary heating fuel, while only 22% use

5 electricity. During the mid-1980s, these numbers were

6 essentially reversed. Where natural gas is available,

7 nearly all new homes install gas heating equipment.

8 Further, as gas prices fell over the past decade, many

9 existing customers switched their heating equipment from

10 electric to gas.

11 Since 1986, the number of residential customers

12 served by the Company

13

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18 /

19

20

21

22

23

24

25

850

Hirschkorn, Di 16A
WWP

1 (including customers acquired from Pacific Corp.) has

2 increased by 41% whereas energy usage and revenue have

3 increased only 27%. Total energy consumption in the

4 higher-rate second and third blocks of Residential

5 Schedule I increased only 16% since 1986. Further, the

6 average rate per kwh paid by residential customers has

7 actually decreased by 2% since 1986, which is consistent

8 with the reduction in average use per customer and the

9 present inverted three-block rate structure. As a

10 result, many of the fixed costs originally designed to be

11 recovered through the second and third blocks of the

12 Schedule are not being recovered at all.

13 Although over 50% of Idaho residential customers

14 use natural gas as their primary heating fuel, over

15 20,000 customers (22%) still use electricity as their

16 primary home-heating source. Over one-quarter of these

17 customers are households with annual income of less than

18 $15,000 per year. Many of these customers either do not

19 have natural gas available or cannot afford to convert to

20 another fuel source. Applying the proposed increase to

21 the present inverted rate structure would further

22 increase winter heating bills for these customers, as

23 opposed to reducing the present rate inversion as

24 proposed.

25 Additionally, much of the customer usage that

851

Hirschkorn, Di 17
WWP

1 occurs in the second and third blocks of the Schedule is

2 weather-sensitive, and can vary from year-to-year

3 depending on the weather. As a result, the present

4 inverted rate structure leads to a higher level of

5 revenue volatility to the Company from year-to-year as

6 compared to a flat or declining-block rate structure.

7 This higher level of revenue volatility caused by the

8 present inverted rate structure only exacerbates the

9 effect which weather has on the Company's operating

10 results.

11 Q. Do any other investor-owned utilities, who

12 provide electric service in

13

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19

20

21

22

23

24

25

852

Hirschkorn, Di 17A
WWP

1 Idaho, presently have an inverted residential rate

2 structure?

3 A. No, they do not. Both Idaho Power and

4 PacifiCorp. have a flat/single energy charge for all kwh

5 use under their residential service schedule(s).

6 Q. Why isn't the Company proposing a

7 flat/single energy rate, rather than retaining a

8 two-block inverted rate structure?

9 A. With the overall amount of the proposed

10 increase to residential customers, together with the

11 proposed basic charge of $5.50 per month, the Company

12 believes that moving part way to a flat energy charge in

13 this proceeding is reasonable. A two-part transition to

14 a flat energy charge would phase in the effect on

15 customers' bills over time. However, if the Commission

16 does not approve the Company its entire proposed increase

17 in this case, it may be reasonable to consider moving to

18 a single energy charge in this proceeding.

19 Q. How did the Company determine the level of

20 the proposed energy rates under Residential Schedule 1?

21 A. First, a weighted-average rate for the

22 present second-and third-block rates was calculated.

23 Next, the revenue from the proposed basic charge of $5.50

24 per month was subtracted from the total proposed revenue

25 increase under the Schedule to determine the revenue

853

Hirschkorn, Di 18
WWP

1 increase to be spread to the energy charges. This

2 revenue increase was then spread to the two energy

3 block-rates on a uniform cents per kwh basis to determine

4 the proposed energy rates.

5 Q. Has the Company estimated the increase to a

6 typical residential customer based on the proposed rates?

7 A. Yes. Page 6, of Exhibit No. 21 shows the

8 estimated monthly and annual

9

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22

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854

Hirschkorn, Di 18A
WWP

1 increase for a typical residential customer. As shown,

2 the increase for a customer using 12,336 kwhs per year is

3 estimated to be an average of $8.88 per month.

4 Q. Is the Company proposing rate structure

5 changes to any of its other service schedules?

6 A. The only additional rate structure change

7 which the Company is proposing is to implement a monthly

8 basic charge for Pumping Schedule 31, which presently

9 contains no monthly minimum charge.

10 Q. Turning to General Service Schedule 11,

11 could you please explain the present rates and charges

12 under the Schedule and how the Company is proposing to

13 spread the proposed increase of 7.5% among those rates

14 and charges?

15 A. General Service Schedule 11 generally

16 serves small commercial customers whose monthly peak

17 demand is less than 50 kilowatts. The Schedule presently

18 contains a monthly basic charge of $4.00, an energy

19 charge of 6.617 cents/kwh, and a demand charge of

20 $3.15/kw for kilowatts in excess of 20 each month.

21 The Company is proposing to increase the monthly

22 basic charge from the present level of $4.00 per month to

23 $6.00 per month. As shown on line 10, Page 5 of Exhibit

24 No. 21, $6.00 per month recovers only the fixed monthly

25 costs associated with a service line, a meter, meter

855

Hirschkorn, Di 19
WWP

1 reading, and billing for a Schedule 11 customer. The

2 proposed basic charge would not contribute to any other

3 system fixed costs. The Company is also proposing to

4 increase the present demand charge of $3.15 per kw to

5 $3.50 per kw. As shown on line 8, column (b) on Page 4

6 of Exhibit No. 21, costs which are allocated to Schedule

7 11 on a demand basis total $7.45/kw (at 9.45% rate of

8 return). The proposed increase to the energy charge

9 under the Schedule is 0.332 cents per kwh, or 5.0%.

10

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856

Hirschkorn, Di 19A
WWP

1 Q. Could you please explain the present rates

2 and charges under Large General Service Schedule 21 and

3 how the Company is proposing to spread the proposed

4 increase of 10.7% among those rates and charges?

5 A. Large General Service Schedule 21 serves

6 commercial and industrial customers whose peak demand is

7 between 50 and 2,500 kw per month. The present rates

8 under the Schedule contain a monthly minimum charge of

9 $200 for the first 50 kilowatts or less, an energy charge

10 of 3.897 cents/kwh, and a demand charge of $2.30/kw for

11 all kilowatts in excess of 50 each month. Primary

12 voltage customers (served at 11 kilovolts or higher)

13 receive a discount of 10 cents per kw.

14 The Company is proposing to increase the monthly

15 minimum charge from $200 to $225 per month, and the

16 present demand charge from $2.30/kw to $2.75/kw. The

17 proposed increase to the energy charge is 0.389 cents/kwh

18 or 10.0%. The Company is proposing to increase the

19 present primary voltage discount from 10 cents per kw to

20 20 cents per kw.

21 At the present voltage discount rate of 10 cents

22 per kw, there is no economic incentive for customers to

23 take service at primary voltage, where feasible. In

24 those instances where a customer is served at primary

25 voltage (11 kilovolts or higher), they are required to

857

Hirschkorn, Di 20
WWP

1 own and maintain electric facilities (step-down

2 transformers, conductor, etc.) on their side of the

3 metering point. Based on a customer taking primary

4 service with a peak demand of 1,000 kw and a 50% load

5 factor, the customer's bill would be about $140/month

6 higher compared to taking service at secondary voltage

7 because transformer losses. Additionally, as the

8 customer is required to own and install the facilities on

9 their side of the metering point, they will want to

10 recover their investment through the voltage

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21

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858

Hirschkorn, Di 20A
WWP

1 discount, which in this case, could exceed $10,000. The

2 amount of the present monthly primary voltage discount

3 for this customer would be about $100. Increasing the

4 discount to the proposed level of 20 cents/kw would

5 provide additional economic incentive for a new customer

6 to take service at primary voltage.

7 Q. How many primary voltage customers does the

8 Company presently serve?

9 A. The Company presently serves only 18

10 customers under Schedule 21 who take service at primary

11 voltage, compared to over 1,700 total customers who take

12 service under the Schedule. All fourteen Schedule 25

13 accounts take service at primary voltage.

14 Q. Could you please explain the present rates

15 and charges under Extra Large General Service Schedule 25

16 and how the Company is proposing to spread the proposed

17 increase of 16.4% among those rates and charges?

18 A. Extra Large General Service Schedule 25

19 requires a minimum monthly demand level of 2,500

20 kilovolt-amperes (kva); eleven customers (fourteen

21 accounts metering points) are presently served under the

22 Schedule. The Schedule contains a monthly minimum charge

23 of $5,500 for the first 3,000 kva or less, an energy

24 charge of 3.036 cents/kwh, and a demand charge of $1.10

25 for all kva in excess of 3,000. There is an annual

859

Hirschkorn, Di 21
WWP

1 minimum charge of $361,350, which is based on 11 million

2 kwhs multiplied by the energy rate plus the monthly

3 minimum charge ($5,500) multiplied by 12 (months).

4 Schedule 25 also contains a present primary voltage

5 discount of 10 cents per kva.

6 The Company is proposing to increase the monthly

7 minimum charge from $5,500 to $7,500 per month. Dividing

8 the proposed minimum charge by the first

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860

Hirschkorn, Di 21A
WWP

1 3,000 kva covered by the minimum charge yields an implied

2 demand charge of $2.50 per kva. Compared to the

3 demand-related costs from the cost of service study, as

4 shown on Page 4 of Exhibit No. 21, this implied charge is

5 still far below the cost of service. Related, the

6 proposed demand charge for all kva in excess of 3,000 is

7 $2.25, as compared to the present level of $1.10/kva.

8 The proposed demand charge will provide customers with a

9 more reasonable indicator of demand-related costs and

10 encourage them to further improve-their load factor. The

11 proposed increase to the energy charge under the Schedule

12 is 0.308 cents/kwh or 11.5%. The proposed annual minimum

13 charge has also been increased to $419,230, based on the

14 same formula as the present charge. The primary voltage

15 discount is proposed to increase from 10 cents to 20

16 cents/kva, as discussed above.

17 Q. Could you please explain the present rates

18 and charges under Pumping Service Schedule 31 and how the

19 Company is proposing to spread the proposed increase of

20 9.6% among those rates and charges?

21 A. Pumping Service Schedule 31 provides

22 service for pumping water (and water effluents) for

23 irrigation, municipal systems, and other purposes. The

24 Schedule contains a two-block declining rate structure,

25 with the first block being 5.962 cents/kwh and the second

861

Hirschkorn, Di 22
WWP

1 block being 4.181 cents/kwh. The amount of energy billed

2 under each block is dependent upon the customer's peak

3 demand and load factor (kwhs per kw of demand).

4 As Schedule 31 presently contains no monthly

5 minimum charge, the Company is proposing to implement a

6 monthly basic charge of $6.00. As shown on line 15 of

7 Page 5 of Exhibit No. 21, the proposed basic charge will

8 recover about 82% of the costs with a service line, a

9 meter, meter reading, and billing. The remainder of the

10 proposed

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862

Hirschkorn, Di 22A
WWP

1 revenue increase to the Schedule is spread equally to the

2 two energy blocks under the Schedule, resulting in an

3 increase of 0.368 cents/kwh.

4 Q. Turning to Street and Area Light Schedules

5 41-49, could you please explain the present rates for

6 service and how the proposed increase of 13.0% was spread

7 among those rates?

8 A. Street and Area Light Schedules contain

9 monthly fixed charges for different light types and

10 sizes, as well as pole types. Company-owned street

11 lights are offered under Schedules 41 and 42, maintenance

12 and energy for customer-owned lights is offered under

13 Schedules 43 and 44, and energy only service is offered

14 under Schedules 45 and 46. Company-owned area lights are

15 offered under Schedules 47 and 49. The proposed increase

16 of 13.0% was applied uniformly to present rates and

17 charges for all street and area lights.

18 Q. Is the Company proposing any other

19 significant changes to its tariffs for electric service

20 in this case?

21 A. No, it is not.

22 Q. Has the Company considered redesigning its

23 general service rate schedules based on voltage level or

24 some other qualification criteria?

25 A. Yes it has, however, the Company has not

863

Hirschkorn, Di 23
WWP

1 performed the analyses necessary to propose any customer

2 qualification/availability changes to its general service

3 schedules at this time. These types of changes require

4 considerable cost allocation and revenue analysis, as

5 well as examination of the potential impacts on

6 individual customers. Changing the

7 qualification/availability criteria under rate schedules

8 can potentially have significant rate impacts on

9 individual customers who may be transferred to another

10 rate

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864

Hirschkorn, Di 23A
WWP

1 schedule; with the level of the proposed increase

2 requested in this case, the Company believes that an

3 examination of potentially significant rate schedule

4 changes may be more appropriate in a future proceeding.

5 With regard to redesigning the Company's general

6 service schedules by voltage level, the Company presently

7 serves only 33 customers at primary voltage (11 kv or

8 higher) and no customers at transmission voltage (55 kv

9 or higher). All 14 customers served under Extra Large

10 General Service Schedule 25 are served at primary voltage

11 and only 18 out of over 1,700 served under Large General

12 Service Schedule 21 are served at primary voltage. Of

13 the 18 customers served under Schedule 21, not all of

14 those are high usage customers, and combining them with

15 Schedule 25 customers solely based on service voltage may

16 not be appropriate.

17 Q. Does that complete your direct testimony in

18 this proceeding?

19 A. Yes it does.

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865

Hirschkorn, Di 24
WWP

1 Q Would you please state your name and

2 present position with the Company.

3 A My name is Brian J. Hirschkorn and I am

4 presently employed by the Company as a Senior Rate

5 Accountant.

6 Q Did you provide direct testimony in this

7 Case?

8 A Yes I did. My testimony addressed the

9 Company's proposed rate spread and rate design in this

10 Case, as well as several pro forma revenue adjustments

11 which "normalize" revenue during the test year.

12 Q Would you please state the scope of your

13 rebuttal testimony in this proceeding?

14 A My rebuttal testimony will address the

15 proposed adjustment of Staff Witness Sterling to impute

16 $1,178,835 as additional Contributions In Aid of

17 Construction (CIAC) and reduce the Company's proposed

18 annual revenue requirement by $100,000. My rebuttal

19 testimony will also address Staff Witness Maxwell's

20 proposed residential basic charge of $4.00 per month as

21 compared to the Company's proposed charge of $5.50.

22 Q Could you please summarize the conclusions

23 you reach in your rebuttal testimony?

24 A Yes. Regarding Mr. Sterling's proposed

25 adjustment, the Company requests that the Commission

866

Hirschkorn, Di-Reb 1
Avista

1 reject the adjustment for the following reasons:

2 1) The adjustment is based more on assumptions

3 than actual data.

4 2) Rejecting Mr. Sterling's proposed

5 adjustment would have a negligible effect

6 on customers' bills.

7 3) The adjustment is proposed after a review

8 of only one aspect of the Company's line

9 extension tariff, whereby a more thorough

10 and collaborative examination of the tariff

11 is a more reasonable proposal.

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867

Hirschkorn, Di-Reb 1A
Avista

1 Regarding the level of the proposed residential

2 basic charge, I will provide information, in addition to

3 that provided in my direct testimony, why the Company's

4 proposed charge of $5.50 is more reasonable and fair to

5 all residential customers, as compared to the Staff's

6 proposed level of $4.00.

7 Staff Proposed Adjustment to CIAC

8 Q Could you briefly summarize Staff Witness

9 Sterling's proposed adjustment?

10 A Yes. Mr. Sterling recommends that

11 $1,178,835 be imputed as CIAC which would result in a net

12 reduction in the Company's Idaho net rate base of

13 $639,000, as shown on Page 2 of Exhibit 118 in Staff

14 case. His proposed adjustment purports that the amount

15 imputed as CIAC should have been collected from new

16 customers added to the Company's system between 1989 and

17 1997, based on a number of assumptions regarding the

18 Company's line extension costs during that period.

19 Q You mentioned that Mr. Sterling's

20 adjustment is based more on assumptions than actual data.

21 Could you explain that statement?

22 A The proposed amount of Mr. Sterling's

23 adjustment is based on a comparison of the Company's

24 average residential line extension costs for the years of

25 1988 and 1997. He then assumes that the Company's line

868

Hirschkorn, Di-Reb 2
Avista

1 extension costs for all of the years in between 1988 and

2 1997 escalated at exactly the rate of escalation of the

3 S&P DRI Price Index (Exhibit No. 110). However, as he

4 shows in an annual analysis of Idaho Power's line

5 extension costs for subdivisions (Exhibit No. 114), line

6 extension costs do not necessarily escalate in a manner

7 comparable to an overall price index.

8 Q How did Mr. Sterling determine the amount

9 of his adjustment?

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869

Hirschkorn, Di-Reb 2A
Avista

1 A Mr. Sterling began with the amount of CIAC

2 the Company collected from customers receiving line

3 extensions in 1988. He then assumed that the amount

4 collected in CIAC each year should escalate commensurate

5 with the DRI Price Index. He then compared his assumed

6 level of CIAC to the actual CIAC collected by the Company

7 for each year from 1988 through 1997. The cumulative

8 difference for the ten-year period is $1,178,835, the

9 amount that Mr. Sterling proposes to impute as additional

10 CIAC.

11 Q How much CIAC did the Company collect from

12 customers during the ten-year period, 1988-1997?

13 A The Company collected approximately $6

14 million in CIAC from customers during the ten-year

15 period, compared to $7.2 million which Mr. Sterling

16 estimates the Company should have collected based on the

17 assumptions he used to develop his estimate. These

18 amounts are shown on Exhibit No. 110 of Mr. Sterling's

19 testimony.

20 Q Does Mr. Sterling's proposed adjustment

21 represent a significant amount of the total investment in

22 distribution plant made by the Company?

23 A No, it does not. During the ten-year

24 period 1988-1997, the Company invested over $117 million

25 in total distribution plant and over $40 million in

870

Hirschkorn, Di-Reb 3
Avista

1 distribution plant directly related to line extensions,

2 as it has added over 30,000 customers during that period,

3 an increase of over 45%. Mr. Sterling's proposed

4 adjustment of $1,178,835 represents less than 3% of the

5 $40 million directly invested by the Company in line

6 extensions, and 1% of the investment in total

7 distribution plant during the ten-year period.

8 Q Does Mr. Sterling claim that the Company

9 investment in distribution plant, equivalent to the

10 amount of his proposed adjustment, was imprudently made?

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871

Hirschkorn, Di-Reb 3A
Avista

1 A No, but his proposed adjustment has the

2 same punitive effect, which the Company believes is

3 unreasonable and excessive in this instance.

4 Q Mr. Sterling states on page 6 of his

5 testimony, lines 21-24, "I do not believe all customers

6 should be burdened with higher rates when much of the

7 cause of the upward rate pressure can be attributed to

8 only a few customers." Would you care to comment on this

9 statement?

10 A Yes. Mr. Sterling's proposed adjustment

11 represents less than 1% of the Company's total proposed

12 increase of $14.2 million. Further, as previously stated

13 in my testimony, the Company added over 30,000 customers

14 during the ten-year period during 1988-1997. I am not

15 sure how these facts correspond to the statement quoted

16 in Mr. Sterling's testimony: "... much of the cause of

17 the upward rate pressure can be attributed to only a few

18 customers."

19 Q You mentioned earlier in your testimony

20 that rejecting Mr. Sterling's proposed adjustment would

21 have a negligible effect on customers' bills. What is

22 your basis for this statement?

23 A Mr. Sterling's proposed adjustment would

24 reduce the Company's proposed annual revenue increase by

25 $100,000. Dividing this amount by the pro forma annual

872

Hirschkorn, Di-Reb 4
Avista

1 kwh sales to Idaho customers of 2.4 billion results in a

2 charge of 0.004 cents/kwh. Multiplying the kwh charge by

3 a typical residential customer usage of 1,000 kwhs/month

4 results in a charge of approximately 4.2 cents/month or

5 50 cents/year, less than one-tenth of one percent of a

6 customer's average bill. This is a very minor effect on

7 customers' bills which would result from rejecting

8 Mr. Sterling's adjustment.

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873

Hirschkorn, Di-Reb 4A
Avista

1 Q You stated earlier in your testimony that

2 Mr. Sterling's proposed adjustment is based on a review

3 of only one aspect of the Company's Line Extension

4 Tariff. Could you explain this statement?

5 A Yes. Mr. Sterling's proposed adjustment is

6 based on a review of the Company's single-party line

7 extension costs only for the years 1988 and 1997, and

8 actual CIAC collected by the Company each year during

9 1988-1997. His adjustment assumes that the Company's

10 single-party costs have escalated annually commensurate

11 with the S&P DRI Price Index and that CIAC actually

12 collected in 1988 should have escalated by the exact

13 amount of his assumed annual cost escalation.

14 Line extensions to subdivisions comprise the

15 majority of residential extensions performed today, and

16 Mr. Sterling concedes on Page 22 of his testimony, lines

17 22-24, "... a more detailed cost analysis would need to

18 be done in order to determine whether costs have, in

19 fact, changed in subdivisions." Further, customer

20 allowances for line extensions should be reviewed in

21 conjunction with a review of the Company's line extension

22 costs, as supported by Mr. Sterling as well on page 24,

23 line 19 of his testimony.

24 Q Despite your objections to Mr. Sterling's

25 proposed adjustment, do you agree with his statements on

874

Hirschkorn, Di-Reb 5
Avista

1 page 24 of his testimony that the Company's line

2 extension tariff needs to be more closely examined - that

3 line extension costs need to be updated, and allowances

4 may need to be revised as well?

5 A Yes. The Company is willing to initiate a

6 collaborative effort with the Commission Staff within

7 ninety (90) days after the conclusion of this Case to

8 review the Company's line extension tariff. Current line

9 extension costs will be updated in the tariff, and

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875

Hirschkorn, Di-Reb 5A
Avista

1 allowances, based on approved rates and cost of service

2 principles in this Case, as well other aspects of the

3 tariff, will be reviewed and revised as deemed

4 appropriate.

5 Residential Basic Charge

6 Q Could you please summarize Staff Witness

7 Maxwell's testimony regarding her proposed level for the

8 Company's residential basic charge.

9 A Yes. Ms. Maxwell proposes that the basic

10 charge for Residential Schedule 1 be set at $4.00 per

11 month as compared to the Company's proposed level of

12 $5.50 per month. The reasons cited by Ms. Maxwell on

13 page 7 of her testimony, lines 10-13 are that "$4.00

14 reduces the high percentage increase on low consumption

15 customers that a $5.50 basic charge places. A $4.00

16 charge is also consistent with other basic charges found

17 in Avista's tariffs."

18 Q Does the Company have any information

19 regarding low electric consumption customers?

20 A Yes. In the past, most low electric

21 consumption customers were thought to be low and fixed

22 income customers. This is certainly not true today. The

23 majority of low-use electric customers use natural gas

24 for space-heating and water-heating. Based on recent

25 customer survey results, 53% of the Company's Idaho

876

Hirschkorn, Di-Reb 6
Avista

1 residential customers use natural gas for space heat,

2 whereas only 22% use electricity as their primary heat

3 source. These figures were essentially reversed a decade

4 ago. Between 1988 and 1998, the number of residential

5 gas customers served by the Company in Idaho grew from

6 17,000 to over 45,000. Gas heat customers enjoy

7 substantially lower total energy bills than non-gas heat

8 customers, and have seen their gas rates decrease by

9 about 10% during the past five years. Generally, these

10 natural gas customers have purchased newer homes or have

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877

Hirschkorn, Di-Reb 6A
Avista

1 converted to gas by making a significant investment in

2 new heating equipment, i.e., the vast majority are not

3 low income customers. In fact, less than 10% of all

4 gas-heat customers are low-income, while 25% of all

5 electric heat customers are low income.

6 Q What is the average electric consumption

7 for gas heat versus non-gas heating customers?

8 A Based on survey results, the average

9 monthly electric consumption for gas-heat customers is

10 approximately 800 kwhs per month, whereas the average

11 monthly electric consumption for non-gas heat customers

12 is approximately 1,200 kwhs per month, or 50% higher than

13 for a gas heat customer.

14 Q Given that most low electric consumption

15 customers are also gas heat customers, why is the

16 Company's proposed basic charge of $5.50 more reasonable

17 and fair to all residential customers, as compared to the

18 Staff's proposed level of $4.00?

19 A A monthly basic charge of $5.50 insures

20 that all residential electric customers, including gas

21 heat customers, are paying a minimal level of the fixed

22 costs required to provide them electric service. This

23 minimal level of fixed costs includes only the cost of

24 the meter, the cost of the service line from the street

25 in front of their residence to their meter, and the

878

Hirschkorn, Di-Reb 7
Avista

1 monthly cost of meter-reading and billing. If the fixed

2 costs of providing basic electric service to gas heat

3 customers are not recovered through a reasonable basic

4 charge, then other electric customers are subsidizing

5 these customers through higher energy charges.

6 Q Is there a cost basis difference between

7 the Company's proposed basic charge of $5.50 and

8 Ms. Maxwell's proposed charge of $4.00?

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879

Hirschkorn, Di-Reb 7A
Avista

1 A Yes. Both proposed charges would recover

2 the cost of the meter, as well as the cost of meter

3 reading and billing each month. The Company's proposed

4 charge would also serve to recover the cost of the

5 service line, which provides electrical service to the

6 customer's home from the nearest electric line, typically

7 from the street in front of their residence.

8 Q Why does the Company believe that the cost

9 of the service line should be recovered through the basic

10 charge?

11 A The cost of the service line is an

12 incremental cost associated with the addition of each new

13 customer. There is a service line dedicated to each

14 customer, just as there is a meter dedicated to each

15 customer, therefore, it makes little sense to include the

16 cost of the meter as a cost to be recovered through the

17 basic charge, but not the cost of the service line.

18 Q Does Ms. Maxwell believe that the Company's

19 proposed level of $5.50 is unreasonable from a cost

20 recovery basis?

21 A It doesn't appear so. On page 6 of her

22 testimony, lines 21-25, she states: "The proposed $5.50

23 basic charge falls within the range of fixed charges

24 previously authorized by this Commission for other

25 utilities, and it is considerably less than the amount

880

Hirschkorn, Di-Reb 8
Avista

1 Avista's cost of service study supports, i.e., $13.04

2 (customer allocated costs) for the residential class."

3 Q Ms. Maxwell states that a $4.00 (basic)

4 charge is consistent with other basic charges found in

5 Avista's tariffs. More specifically, she cites the $4.30

6 basic charge for residential service under the MOPS II

7 experiment and the $4.00 per month optional

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881

Hirschkorn, Di-Reb 8A
Avista

1 seasonal charge under Residential Schedule 1. Do you see

2 any critical inconsistencies between these charges and a

3 residential basic charge of $5.50?

4 A No, I do not. The Company will file

5 revised MOPS II tariffs based on the rates approved in

6 this Case, as proposed in the Company's MOPS II

7 application. The Company would revise the basic charges

8 under the MOPS tariffs to match the basic charges

9 approved by the Commission for its general service

10 tariffs so that there is not an inappropriate incentive

11 for customers to switch to service under MOPS.

12 The $4.00 optional seasonal charge under

13 Residential Schedule 1 is applied to customers who close

14 their account on a seasonal basis. The amount of the

15 seasonal charge must be examined in conjunction with the

16 Company's reconnection charge, otherwise there may be an

17 incentive for customers to disconnect and pay the

18 reconnection fee as opposed to seasonally closing their

19 account. Presently, if a customer desires to close their

20 account for up to six months, they would opt for the

21 optional seasonal charge rather than disconnecting their

22 service and paying the reconnection fee. If the optional

23 seasonal charge is increased to $5.50 and the

24 reconnection fee stays at its present level of $24, then

25 a customer who desires to close their account for more

882

Hirschkorn, Di-Reb 9
Avista

1 than four months would be financially better off

2 requesting a disconnect and paying the reconnection

3 charge. The Company would not have a problem with

4 increasing the optional seasonal charge to $5.50, as long

5 as the reconnection charge is increased commensurately.

6 Q Is there any reason why the optional

7 seasonal charge must match the monthly basic charge?

8 A No, there is not.

9 Q Does that complete your rebuttal testimony

10 in this proceeding?

11 A Yes, it does.

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883

Hirschkorn, Di-Reb 9A
Avista

1 (The following proceedings were had in

2 open hearing.)

3 MR. MEYER: And with that, Mr. Hirschkorn

4 is available for cross.

5 COMMISSIONER SMITH: Mr. Ward.

6 MR. WARD: I just have one, maybe two

7 questions, Mr. Hirschkorn.

8

9 CROSS-EXAMINATION

10

11 BY MR. WARD:

12 Q Your Exhibit 26, regardless of what's been

13 said about the Potlatch special contract heretofore, your

14 Exhibit 26 clearly shows that that contract is earning

15 well above unity in terms of cost of service, does it

16 not?

17 A It does on my exhibit, but I might add that

18 the exhibit reflects only the amount of revenues which

19 are directly assigned to Idaho. It doesn't reflect those

20 dollars that are allocated between the two states to

21 match the purchased power.

22 Q I understand that.

23 A Okay.

24 MR. WARD: Thank you. That's all I have.

25 COMMISSIONER SMITH: Mr. Shurtliff.

884

CSB REPORTING HIRSCHKORN (X)
Wilder, Idaho 83676 Avista

1 MR. SHURTLIFF: Thank you.

2

3 CROSS-EXAMINATION

4

5 BY MR. SHURTLIFF:

6 Q First, directing your attention to your

7 rebuttal testimony, Mr. Hirschkorn, as to the proposition

8 that's advanced by Mr. Sterling, you discuss that at

9 length, would it be fair to say that you characterize

10 Mr. Sterling's testimony as suggesting that some

11 underrecovery from customers for distribution plant

12 occurred; is that where he goes?

13 A That's the basis of his testimony which the

14 Company takes issue with in my rebuttal.

15 Q You disagree with that?

16 A Yes, we do.

17 Q He's wrong?

18 A We have -- well, I point out several

19 problems with Mr. Sterling's analysis in my rebuttal

20 testimony. One area that I didn't point out in my

21 rebuttal testimony was the basis for his calculation of

22 this additional contribution in aid of construction which

23 he imputes in his testimony and thereby reducing or

24 proposing to reduce the Company's revenue requirement by

25 $100,000.

885

CSB REPORTING HIRSCHKORN (X)
Wilder, Idaho 83676 Avista

1 I'd like to kind of take a minute and walk

2 through Mr. Sterling's analysis. It's on Exhibit 112 of

3 Mr. Sterling's testimony. This exhibit was the basis for

4 his proposed adjustment imputing additional contributions

5 in aid of construction, thereby reducing the Company's

6 rate base. The next to the last column shows the

7 percentage increase or decrease in the various line

8 extension costs of the Company between 1989 and 1997.

9 The last number in that column is 25.18

10 percent. I'd like to point out that that number was

11 computed on a simple average method. It doesn't take

12 into account the dollars for the various items of line

13 extension costs. I've taken a look at that in the last

14 couple of days and recomputed that number on a weighted

15 average basis and that number would actually be less than

16 four percent on a weighted average as opposed to 25

17 percent.

18 If you take that number, the four percent

19 number, through the rest of Mr. Sterling's adjustment,

20 the reduction in the Company's revenue requirement would

21 be approximately $15,000 rather than $100,000. That's

22 just one of the problem areas that we found with

23 Mr. Sterling's adjustment. It also doesn't give weight

24 to the number of line extensions that the Company now

25 does for subdivisions versus single parties, so the

886

CSB REPORTING HIRSCHKORN (X)
Wilder, Idaho 83676 Avista

1 Company has a number of problems with Mr. Sterling's

2 adjustments and we don't think it's appropriate to make

3 that adjustment in this case.

4 Q Notwithstanding your disagreement with his

5 methodology and/or conclusion, you agree at page 5 of

6 your redirect that nonetheless, that you believe, that

7 you indicate the Company is willing to initiate a

8 collaborative effort with the Commission Staff to address

9 some of the concerns he raises in regard to the line

10 extension policy.

11 A Yes, we are. We think the entire tariff

12 needs to be looked at, not just one element of the

13 tariff.

14 Q And so his concerns in that regard you do

15 agree with?

16 A Yes.

17 Q So it's possible that he can come to the

18 correct determinations, I take it?

19 A Well, I don't think he has in his

20 testimony. I think the entire tariff needs to be

21 reviewed, discussed at some length between the Company

22 and the Staff in all aspects of the tariff, not just one

23 aspect.

24 Q If you will assume with me, and it is an

25 assumption, I'm asking you to assume because you disagree

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1 with the proposition that Mr. Sterling is correct in his

2 analysis of what we could characterize as undercollection

3 of certain monies from the line extension situation, if

4 you assume the correctness of that, who benefited from

5 that undercollection in that assumption?

6 A I will make that assumption as you set

7 forth. It was a very small amount of dollars in terms of

8 our total investment in plant over the past 10 years.

9 Actually, it was approximately one percent of our total

10 distribution investment. Mr. Sterling's adjustment

11 represents that. If in fact there was a benefit, a few

12 customers perhaps didn't pay an additional contribution

13 toward their line extension. As I point out in my

14 rebuttal, even if one were to accept or assume

15 Mr. Sterling's adjustment is correct, the effect of that

16 would be to increase residential customer bills by about

17 $.50 a year. Using the revised calculation I've done of

18 reducing the Company's revenue requirement by $15,000 a

19 year would be about four cents a year, so very little

20 impact on the other customers served by the Company.

21 Q Did you calculate the pennies that it would

22 make difference under either the numbers propounded by

23 Mr. Sterling or your recalculation of that to the three

24 mining companies that I represent?

25 A No, I have not.

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1 Q Did you ever hear, you're too young, you

2 probably never heard of Senator Everett Dirksen?

3 A Unfortunately, I'm not that young. Yes, I

4 have.

5 Q You start talking about pennies and they

6 add up to dollars?

7 A Yes.

8 Q At page 6 of your direct testimony, you

9 talk about how you spread the rates and those sorts of

10 things, so I take it you're the concluding witness in

11 this case and after Mr. Avera provided his professional

12 analytical skill and work and other people did as well

13 that you come to a number, a dollar volume that they

14 concluded is necessary and then you're asked to spread

15 those rates among the different customer classes to

16 recoup those dollars that the rest of the folks here who

17 provided testimony concluded were just and reasonable?

18 A That's correct.

19 Q But you didn't do that mathematically, did

20 you? You didn't just take those numbers and apply a

21 formula to them, did you?

22 A No, we used the cost of service study as a

23 principal guide as well as other rate design

24 considerations in the spread of the proposed increase.

25 Q And those other rate design considerations

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1 require the exercise of judgment, do they not?

2 A Yes, they do.

3 Q So you don't have common numbers that you

4 just provide, you had to include, I think, some judgments

5 as to how far to reach to get to what you characterize as

6 unity?

7 A Yes, that's correct.

8 Q And so you concluded, and I'll assume for

9 purposes of the question that all the dollars that the

10 Company has requested are appropriate in this case, you

11 set out that you didn't decide to get to unity at the

12 present time with those numbers because of a number of

13 different factors that you thought mitigated against

14 going to unity?

15 A That's correct.

16 Q And those factors, again, were in the

17 exercise of judgment?

18 A Yes, they were.

19 Q And so when you conclude at page -- I think

20 it's at page 11 of your direct testimony, those are the

21 numbers at the top of that page that would be necessary

22 to arrive at unity; right?

23 A Yes, that's correct.

24 Q On page 10 are the numbers that you

25 proposed, however?

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1 A Yes, that shows the relative rates of

2 return that result from the Company's proposal, yes.

3 Q In that regard, could you have determined

4 that in the exercise of some aspects of judgment that

5 this spread could be even different than you suggested?

6 A We looked at a number of different rate

7 spreads using, again, cost of service as a principal

8 guide because it is an objective measurement, but with

9 all the other considerations rolled in, we looked at

10 one-quarter movement toward unity, one-third, one-half.

11 We talked about -- looked at the various large customers,

12 looked individually at them, how that would affect them

13 in terms of the proposed revenue increase, looked at the

14 effects on residential customer bills, so we looked at a

15 number of factors.

16 Q In that regard, other people looking at the

17 same information could come to a different judgment as to

18 how these rates ought to be spread, could they not?

19 A Oh, they could, yes.

20 Q And that would not be mathematically

21 impure, it might be impure from the notion of your

22 judgment, it might be a difference in judgment, but it

23 wouldn't be impure mathematically, would it?

24 A No.

25 Q So if someone were to consider in the

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1 context of how to spread the rates the impact on

2 individual customers, you do that, do you not?

3 A Yes.

4 Q And so different people can have different

5 perspectives as to the impact on individual customers and

6 what they can bear or ought to bear in regard to a rate

7 increase; is that not correct?

8 A Yes, that's correct.

9 Q And so you took a look, I think you just

10 said, at the impact on residential customers.

11 A Yes.

12 Q And what it's going to do to their monthly

13 billing and so forth.

14 A Yes.

15 Q And why do you do that? Why do you care?

16 A We want to make sure residential customers,

17 that we're not being unfair in terms of the amount of the

18 proposed increase to each of the customer classes and

19 unfortunately, this is a fairly significant increase. We

20 have had not had an increase since 1986, so we tempered

21 the amount of movement toward cost of service, toward

22 unity for each of the customer schedules. If we went

23 straight across the board in terms of an equal percentage

24 increase, it would be approximately 11 percent and we

25 felt that anything over 15, 16 percent to any one

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1 schedule was probably unacceptable in this case.

2 Q You felt that anything over 15, 16 percent

3 was unacceptable. What if I felt, but I'm no expert, I

4 can't feel, what if somebody else felt that any increase

5 over 12 percent would be unfair, would they be way off

6 the mark in their feeling?

7 A As you mentioned, there's a certain amount

8 of judgment that goes into rate design. Impacts on

9 individual customers need to be considered.

10 MR. SHURTLIFF: Thank you. I have nothing

11 further.

12 COMMISSIONER SMITH: Mr. Woodbury.

13 MR. WOODBURY: Thank you, Madam Chair.

14

15 CROSS-EXAMINATION

16

17 BY MR. WOODBURY:

18 Q Hello, Mr. Hirschkorn.

19 A Good morning.

20 Q Where you left off was impacts to

21 customers --

22 A Yes.

23 Q -- I guess that's where I'll pick up.

24 Looking at your direct testimony at page 8, you're

25 speaking of the residential Schedule 1.

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1 A Yes.

2 Q And you state that electricity is the

3 primary heat source for 22 percent of your customers.

4 A Yes, that's correct.

5 Q And natural gas for 55 percent and the heat

6 source for the remaining percentage of your customers

7 would be what, wood?

8 A Wood, oil and propane are the three other

9 primary sources.

10 Q Of the customers that you've identified as

11 the primary heat source being electricity, you state --

12 before it was much a greater number, now it's over a

13 quarter of those have annual incomes of less than $15,000

14 per year.

15 A Yes, that's correct.

16 Q Elsewhere in your testimony, you speak of

17 low income customers, are we speaking of the same people

18 here, less than 15,000?

19 A Yes, we are.

20 Q And is this 15,000 for a family of four?

21 A That's an average income level that we

22 used. We didn't have the exact household size. I

23 believe for a family of four between 16 and $17,000 is

24 considered low income, slightly less than 15,000 for a

25 family of three, so we used an average of 15,000.

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1 Q And is it closer to, like, 9,000 for a

2 family of one?

3 A I don't know that, but I would guess that

4 would probably be true.

5 Q And how do you determine that 25 percent of

6 your customers are low income? Is that from a regional

7 study?

8 A That was based on a customer survey we did

9 in late '97/early '98, we surveyed customers.

10 Q What was your sample?

11 A I apologize, I don't have the specific

12 information on the customer survey. It was a

13 statistically valid customer survey, but I don't have the

14 sample size.

15 Q Would it be fair to also believe that the

16 23 percent, I guess, that use something other than

17 electricity or natural gas a percentage of those would be

18 low income, also?

19 A You mean the remaining 23 percent?

20 Actually, there's only about, between five and ten

21 percent of all low income customers use a fuel source,

22 primary fuel source, other than electricity or gas which

23 actually kind of surprised me.

24 Q You state that since '85 the Company has

25 experienced a decline in average use per customer of

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1 10 percent, putting the average customer at about 12,500

2 kilowatt-hours per year.

3 A Yes, that's correct.

4 Q And you crank that out to be for Schedule 1

5 customers about $8.88 per month.

6 A Yes, that's correct.

7 Q And that's for the average customer. Would

8 a customer using electricity for a primary heat source,

9 space heating, would he be above or below that average?

10 A He would be below. I'm sorry, they would

11 be above that average.

12 Q So that customers with -- so those

13 customers in low income using the primary heat source,

14 the effect on them would be greater than 8.88 per month?

15 A Those customers using electricity --

16 Q Low income customers.

17 A It does vary by consumption and with the

18 rate design changes we've done, if you look on page 4 of

19 my exhibit, it shows the monthly increase for a typical

20 residential customer. Actually, that's of my revised

21 exhibit.

22 Q Which exhibit?

23 A Exhibit No. 26.

24 Q Okay.

25 A If you look at the last column, that shows

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1 the monthly increase by month for a typical residential

2 customer with the various usage levels in there. You can

3 see how it varies depending on the usage level each

4 month.

5 Q On page 12 of your direct testimony, you

6 state that if this Commission approves a revenue increase

7 less than requested, it is the Company's proposal that

8 the Commission consider a rate spread which accelerates

9 the move to unity, which would be a move greater than

10 one-third that the Company is proposing in this case?

11 A Yes.

12 Q And does the Company have a suggestion as

13 to how far the Commission should move along that path?

14 A No, we don't have a specific suggestion in

15 terms of how far that movement might be. They might

16 consider a movement up to one-half depending on the

17 impacts on customer classes.

18 Q And keeping in mind that if that were to

19 equate to a percentage increase greater than 15, 16

20 percent that it might be unacceptable?

21 A That was the Company's conclusion in this

22 case.

23 Q Okay. The Company is also proposing moving

24 off of the three-block inverted rate, essentially

25 transitioning to a flat rate as used by Idaho Power and

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1 PacifiCorp.

2 A Yes, that's correct.

3 Q And you state that, giving some historical

4 background for going to the inverted rate, it was

5 implemented to send a price signal to customers that

6 reflected the higher incremental cost of new generation,

7 but I guess what I would ask you now is why is a

8 conservation signal no longer appropriate in electricity?

9 A Well, I think a conservation signal is

10 appropriate, but there are specific conservation programs

11 with regard to weatherizing homes. We do a certain

12 amount of fuel switching for customers still through DSM,

13 especially limited income customers. I think with regard

14 to price signals as they relate to incremental

15 generation, I don't think our three-tiered inverted rate

16 schedule is still appropriate.

17 The incremental cost of that additional

18 generation, more and more utilities are looking at

19 smaller increments of additional generation, gas

20 turbines, those types of units, where the fixed costs

21 aren't so high.

22 Q Did the Company do any study to determine

23 whether or not the three-block rate structure did affect

24 customer usage?

25 A We came to the conclusion looking at

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1 customer usage over time with the number of conversions

2 from electric to gas and the decrease in the last two

3 blocks of the schedule in terms of customer usage, it

4 just falls out that overall customer usage has decreased,

5 the usage in those last two blocks has also decreased, so

6 between the price signals as far as our three-block

7 schedule and the cheaper price of gas, customers have

8 taken steps to reduce their consumption.

9 Q Do you anticipate that moving to a single

10 block that the usage will increase?

11 A No, no, not at all, because we still have

12 to recover the same amount of revenue, so that single

13 rate has to got to move somewhere in the middle of those

14 three blocks, so, no, we don't expect usage to increase.

15 Q You also state that if the Commission does

16 not approve the entire proposed increase that it may be

17 reasonable also for the Commission to consider moving to

18 a single energy charge in this proceeding.

19 A Yes.

20 Q And does the Commission have any discretion

21 or latitude in that?

22 A That's up to the Commission. I put that

23 forth in my testimony just to show that the Company would

24 be open to that.

25 Q All right, and from a customer relations

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1 standpoint, you don't find that either of these proposals

2 would be difficult for you to convey to your customers as

3 far as the change?

4 A I think we're one of the few utilities left

5 with an inverted residential rate structure and we

6 believe phasing that out is appropriate at this time. As

7 long as the individual increase or the increases on

8 individual customers are considered as well, I think we

9 can convey that message to customers.

10 Q Okay. The effect of change to your pumping

11 service customers, originally you had it at 9.6 percent

12 increase that you were requesting in rates and now it's

13 8.6 percent, is that inclusive or exclusive of the

14 monthly basic charge?

15 A That includes the basic charge.

16 Q Okay. Moving on to your rebuttal

17 testimony, in 1989, the Company filed an application with

18 this Commission requesting revisions to its line

19 extension tariffs, did it not?

20 A Yes, that's correct.

21 Q And in the Commission's Order in that case

22 the following year, Order No. 23071, the Company was --

23 the Commission's language reads, "The Company is to

24 provide the Commission annually with updated worksheets

25 and average unit costs for Schedule 51 construction and

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1 to update its tariff as necessary to keep the costs

2 current."

3 Has the Company ever provided updated

4 average unit costs as required by the Commission's Order?

5 A We have not. Even though we have done

6 numerous reviews internally, we have not provided that

7 information to the Commission, and as I stated prior,

8 those costs in total when looked at on an overall basis

9 have really not increased that much over that nine-year

10 period, but it was an oversight on the Company's part and

11 the Company apologizes for not providing that

12 information.

13 Q Well, it wasn't that you just tucked the

14 Order away because we did receive a letter from

15 Mr. Dukich the following year assuring us that they would

16 be forthcoming.

17 A I did see that letter and that was an

18 oversight on the Company's part.

19 Q Have the -- it's not your testimony that

20 the costs of these items have not changed since 1989?

21 A No, they have changed. Some have gone up

22 and some have actually gone down, the various line

23 extension costs.

24 Q And you indicated that although you didn't

25 provide the Commission with the data that you were

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1 essentially doing this in-house?

2 A I'm sorry?

3 Q Providing the updated worksheets, average

4 unit costs, you were performing that analysis in-house,

5 you just weren't sharing it with us?

6 A Yes, primarily because -- well, it was an

7 oversight in terms of we were required to file the

8 workpapers, but, yes, we were looking at it internally

9 during those years.

10 Q And the annual data that you had have you

11 shared with Staff?

12 A The data that I mentioned earlier?

13 Q Uh-huh.

14 A I have not, but I do have copies of that.

15 Q Is it reasonable to conclude that some of

16 the increase in the revenue requirement caused by

17 addition of distribution plant is attributable only to

18 new customers?

19 A Yes, but most of those costs are covered

20 via our line extension tariff.

21 Q Would it be reasonable to have required

22 those new customers to pay for those costs as opposed to

23 spreading them across --

24 A Well, in fact, our contention is that as

25 far as we can tell, almost all of those costs were paid

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1 by new customers, those amounts that aren't covered by

2 our line extension tariff. We in fact collected over

3 $6 million in contributions in aid of construction from

4 new customers during this time period. Mr. Sterling's

5 adjustment imputes an additional 1.2 million that based

6 on his calculation he feels should have been collected in

7 addition by the Company and that's the amount we're

8 taking issue with.

9 Q In your criticism of Staff's case, you

10 state that Staff's adjustment is based on assumptions

11 rather than actual data. Staff in fact in production

12 request No. 45 asked for updated '97 costs in

13 sections 5 and 7 of the Company's line extension tariff.

14 Isn't it true that the Company's response to that request

15 was "The corresponding costs using '97 cost information

16 and presented on a comparable basis are not readily

17 available"?

18 A Yes, it was. I think in a later data

19 response we provided 1997 line extension cost

20 information. I can get that number.

21 Q We asked for the same information in

22 production request No. 57.

23 A Yes, and I believe that's where the

24 information was presented. It was not available at the

25 time of the first data request and I believe the response

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1 to the second data request you referred to was that our

2 engineering department had determined those numbers at

3 that time and they were provided.

4 Q Rather than just, I guess, criticize

5 Staff's method, why didn't the Company in its rebuttal

6 testimony use the actual data and provide the analysis?

7 A Quite frankly, that was an oversight on my

8 part. I did not thoroughly review Mr. Sterling's, the

9 sheet that I referred to earlier, his Exhibit 112, prior

10 to the preparation of my rebuttal testimony. I just

11 realized what I believe is a misleading calculation in

12 his adjustment a couple of days ago and I felt it was

13 important to point it out.

14 Q I understand that essentially you've

15 indicated a willingness to provide the actual data so

16 that more accurate contributions in aid of construction

17 contributions can be determined.

18 A Yes. In fact, we propose and agree with

19 Mr. Sterling that the Staff and Company should get

20 together and review the entire tariff.

21 Q And do I understand your testimony, though,

22 to be also that you believe that you did collect the

23 correct amount of contributions for each and every year

24 between '88 and --

25 A Quite frankly, we're not even sure, because

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1 one thing that we don't have is a weighting of, say, the

2 number of subdivisions we have line extensions to as

3 opposed to single parties and that information would need

4 to be looked at to determine the appropriate amount on an

5 annual basis. We didn't even have that information

6 available.

7 What we did was take an additional step

8 that Mr. Sterling didn't take and look at the differences

9 in cost and weight them by the actual cost. To do it

10 properly should be, it should go one step further and

11 look at the number of line extensions for subdivisions as

12 well as single parties on an annual basis and that

13 information wasn't available.

14 Q Well, if the information isn't available

15 even to the Company as far as brought together, you know,

16 isn't it just as possible that Staff's estimate is too

17 low as opposed to too high?

18 A I don't think so, because what it does is

19 Staff's method looks at all the costs and just presents a

20 simple average of those costs. We know over time we've

21 provided more extensions to subdivisions than we did

22 10 years ago and in fact, those costs have actually gone

23 down because of the density of homes and the shorter

24 service line that we run to connect homes in

25 subdivisions, so I don't think so based on the analysis

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1 I've done.

2 Q Also in your critique, you state that

3 actually Staff's proposed adjustment would have a

4 negligible effect on a customer's bill.

5 A Yes.

6 Q And yet, Staff's proposed adjustment was,

7 like, $1.2 million.

8 A Right.

9 Q You know, so although it may be negligible

10 if you divided it among all your customers, it's still a

11 substantial amount.

12 A It's a substantial amount in total to the

13 Company, $100,000 a year is a significant amount. When

14 you spread it amongst a billion kilowatt-hours, I believe

15 it becomes relatively insignificant to the average

16 customer.

17 Q You're not saying that there's perhaps a

18 threshold of significance that we should be using below

19 or above which adjustments should not be made?

20 A No, I'm not.

21 Q Are you able to identify what other aspects

22 of the line extension tariff should be included in a

23 review to determine how much contributions in aid of

24 construction should be collected?

25 A The other primary element of the tariff

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1 that needs to be reviewed is the customer allowance,

2 basically how much a customer is allowed in terms of cost

3 to extend them service. The tariff revolves around cost

4 versus the allowance and those two factors need to be

5 reviewed in conjunction.

6 Q Okay. The collaborative effort that you

7 propose is prospective or do you think that we should be

8 looking at essentially the past 10 years to determine how

9 much should have been collected?

10 A I think it needs to be prospective, it

11 needs to start from today, look at what our costs are

12 today, what the proper amount of allowance should be,

13 move forward with those, the proper allowance and the

14 current costs of the Company and reviewed periodically

15 and updated.

16 Q You don't think that essentially performing

17 the analysis to review the last 10 years would provide

18 you any information that would be of value?

19 A To the extent that information is

20 available, yes, I think it would provide some guidance in

21 moving forward, but the past isn't always an indicator of

22 the future and we've taken significant steps over the

23 years to hold line extension costs down, not to say that

24 we won't do that in the future, we certainly will because

25 we feel new customers should bear the costs of

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1 new line extensions, but the past isn't always an

2 indicator of the future. I think we need to review the

3 tariff and those components moving forward.

4 Q And you would agree that there's a direct

5 link between line extension allowances and rates; in

6 other words, you know, isn't the amount of the allowance

7 offered by the Company dependent upon how much

8 distribution plant investment is supported by rates?

9 A Yes. The allowance can vary depending on a

10 number of factors, depending on what costs -- there's a

11 certain amount of usage assumed for a customer that goes

12 into the allowance and certain costs that are considered

13 to be recovered. You could just look at incremental

14 costs of putting the service line in as well as the

15 primary and secondary circuit or you can provide an

16 allocation of fixed costs that are covered by the

17 allowance as well, so there is a number of factors that

18 go into determining the amount of the allowance.

19 Q And if rates do not change, should the

20 allowance change?

21 A I guess that's a decision to be

22 determined. We need to look at what is included in the

23 allowance. Right now the allowance allows for a

24 first-year recovery of the rate of return by a new

25 customer and it contributes to the fixed costs of the

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1 Company as well which is a fairly conservative

2 allowance.

3 MR. WOODBURY: Thank you, Mr. Hirschkorn.

4 I appreciate your patience, it's five after 12:00. The

5 Staff has no further questions.

6 COMMISSIONER SMITH: Are there questions

7 from the Commission?

8 COMMISSIONER HANSEN: I have one.

9 COMMISSIONER SMITH: Commissioner Hansen.

10

11 EXAMINATION

12

13 BY COMMISSIONER HANSEN:

14 Q Mr. Hirschkorn, just a follow-up to

15 Mr. Woodbury's question, but I'm kind of concerned on

16 your rebuttal testimony on page 4, lines 16 through 22,

17 where you talk about Mr. Sterling's $100,000 adjustment

18 and if I follow you correctly on line 21, you state that

19 this has a minor effect on customers' bills which would

20 result from rejecting Mr. Sterling's adjustment, and do

21 you think any adjustment of 100,000 or less, or do you

22 have a number, a minimum number, that the Commission

23 should reject any adjustment, whether it's right or

24 wrong, based on a dollar value?

25 A No, I don't, and the basis of my testimony

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1 there was if the Commission is to reject Mr. Sterling's

2 adjustment, this would be the effect and in my opinion, I

3 felt that $.50 a year was a minor amount and that's a

4 matter of opinion and $.50 a year might be a more

5 significant amount to somebody else in their opinion. I

6 just wanted to convey what this meant to the average

7 customer if the adjustment was to be rejected.

8 Q So you don't think the Commission should

9 set a minimum on adjustments that should be accepted or

10 rejected?

11 A That wasn't the basis for my testimony.

12 COMMISSIONER SMITH: Redirect, Mr. Meyer.

13

14 REDIRECT EXAMINATION

15

16 BY MR. MEYER:

17 Q Mr. Shurtliff asked you a series of

18 questions, some of which talked about the extent to which

19 classes were being moved closer to unity. Simply put,

20 was your objective as reflected in Exhibits 21 and 26 to

21 move every class approximately one-third closer to unity?

22 A Yes, it was.

23 Q Okay. Lastly, turn to your Exhibit 26,

24 please, page 2 of 26.

25 A I have that.

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1 Q Line 7, Potlatch special contract, now, the

2 percentages shown there reflect a direct assignment of

3 costs relating to that special contract; correct?

4 A Direct assignment and there are some costs

5 that are allocated in the cost of service study as well.

6 Q But the bulk of the adjustments in the

7 preceding lines, all other schedules, have costs that are

8 allocated based on the extensive cost of service study?

9 A Yes, that's correct.

10 MR. MEYER: Thank you. One more?

11 Q BY MR. MEYER: So in that sense, are they

12 comparable?

13 A The Potlatch special contract does not

14 include all the sales to Potlatch's Lewiston plant. It

15 only, as I stated earlier, only includes the amount which

16 is directly assigned to the State of Idaho. Most of the

17 revenue in kilowatt-hour sales to the Lewiston plant are

18 allocated between the two states to offset the purchased

19 power amount that the Company purchases from the Potlatch

20 Lewiston plant, so it's not really comparable because it

21 doesn't include all their kilowatt-hour sales to the

22 plant.

23 MR. MEYER: That will do it. Thanks.

24 COMMISSIONER SMITH: Thank you, and thank

25 you for your help, Mr. Hirschkorn.

911

CSB REPORTING HIRSCHKORN (Di)
Wilder, Idaho 83676 Avista

1 THE WITNESS: Thank you.

2 (The witness left the stand.)

3 COMMISSIONER SMITH: I take it that's the

4 conclusion of the Company's direct case.

5 MR. MEYER: Right, and rebuttal, reserving

6 the right. If we could be off the record for

7 scheduling?

8 COMMISSIONER SMITH: Okay, let's be at

9 ease.

10 (Off the record discussion.)

11 (Noon recess.)

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25

912

CSB REPORTING COLLOQUY
Wilder, Idaho 83676